

[Federal Register: May 1, 2007 (Volume 72, Number 83)]
[Rules and Regulations]               
[Page 23899-24014]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr01my07-8]                         
 

[[Page 23899]]

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Part II





Environmental Protection Agency





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40 CFR Part 80



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


[[Page 23900]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2005-0161; FRL-8299-9]
RIN 2060-AN76

 
Regulation of Fuels and Fuel Additives: Renewable Fuel Standard 
Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: Under the Clean Air Act, as amended by Section 1501 of the 
Energy Policy Act of 2005, the Environmental Protection Agency is 
required to promulgate regulations implementing a renewable fuel 
program. The statute specifies the total volume of renewable fuel that 
the regulations must ensure is used in gasoline sold in the U.S. each 
year, with the total volume increasing over time. In this context, this 
program is expected to reduce dependence on foreign sources of 
petroleum, increase domestic sources of energy, and help transition to 
alternatives to petroleum in the transportation sector. The increased 
use of renewable fuels such as ethanol and biodiesel is also expected 
to have the added effect of providing an expanded market for 
agricultural products such as corn and soybeans. Based on our analysis, 
we believe that the expanded use of renewable fuels will provide 
reductions in carbon dioxide emissions that have been implicated in 
climate change. Also, there will be some reductions in air toxics 
emissions such as benzene from the transportation sector, while some 
other emissions such as oxides of nitrogen are expected to increase.
    This action finalizes regulations designed to ensure that refiners, 
blenders, and importers of gasoline will use enough renewable fuel each 
year so that the total volume requirements of the Energy Policy Act are 
met. Our rule describes the standard that will apply to these parties 
and the renewable fuels that qualify for compliance. The regulations 
also establish a trading program that will be an integral aspect of the 
overall program, allowing renewable fuels to be used where they are 
most economical while providing a flexible means for obligated parties 
to comply with the standard.

DATES: This final rule is effective on September 1, 2007. The 
incorporation by reference of certain publications listed in the rule 
is approved by the Director of the Federal Register as of September 1, 
2007.

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 EPA 

Docket Center, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., 
NW., Washington, DC. This Docket Facility 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 EPA Docket Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Julia MacAllister, U.S. Environmental 
Protection Agency, National Vehicle and Fuel Emissions Laboratory, 2000 
Traverwood, Ann Arbor MI, 48105; telephone number (734) 214-4131; fax 
number (734) 214-4816; e-mail address macallister.julia@epa.gov.

SUPPLEMENTARY INFORMATION:

I. General Information

    Entities potentially affected by this action include those involved 
with the production, distribution and sale of gasoline motor fuel or 
renewable fuels such as ethanol and biodiesel. Regulated categories and 
entities could include:

------------------------------------------------------------------------
                                                         Examples of
          Category            NAICS \1\   SIC \2\        potentially
                                codes      codes     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.
------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS).
\2\ Standard Industrial Classification (SIC) system code.

    This table is not intended to be exhaustive, but provides a guide 
for readers regarding entities likely to be regulated by this action. 
This table lists the types of entities that EPA is now aware could 
potentially be affected by this action. Other types of entities not 
listed in the table could also be affected. To decide whether your 
organization might be affected by this action, you should carefully 
examine today's notice and the existing regulations in 40 CFR part 80. 
If you have any questions regarding the applicability of this action to 
a particular entity, consult the persons listed in the preceding FOR 
FURTHER INFORMATION CONTACT section.

Table of Contents

I. Introduction
    A. The Role of Renewable Fuels in the Transportation Sector
    B. Requirements in the Energy Policy Act
    C. Development of the RFS Program
II. Overview of the Program
    A. Impacts of Increased Reliance on Renewable Fuels
    1. Renewable Fuel Volume Scenarios Analyzed
    2. Emissions
    3. Economic Impacts
    4. Greenhouse Gases and Fossil Fuel Consumption
    5. Post 2012 RFS Standards
    B. Program Structure
    1. What Is the RFS Program Standard?
    2. Who Must Meet the Standard?
    3. What Qualifies as a Renewable Fuel?
    4. Equivalence Values of Different Renewables Fuels
    5. How Will Compliance Be Determined?
    6. How Will the Trading Program Work?
    7. How Will the Program Be Enforced?
    C. Voluntary Green Labeling Program
III. Complying With the Renewable Fuel Standard
    A. What Is the Standard That Must Be Met?
    1. How Is the Percentage Standard Calculated?
    2. What Are the Applicable Standards?
    3. Compliance in 2007

[[Page 23901]]

    4. Renewable Volume Obligations
    B. What Counts as a Renewable Fuel in the RFS Program?
    1. What Is a Renewable Fuel That Can Be Used for Compliance?
    a. Ethanol Made From a Cellulosic Feedstock
    b. Ethanol Made From any Feedstock in Facilities Using Waste 
Material To Displace 90 Percent of Normal Fossil Fuel Use
    c. Ethanol That Is Made From the Non-Cellulosic Portions of 
Animal, Other Waste, and Municipal Waste
    d. Foreign Producers of Cellulosic and Waste-Derived Ethanol
    2. What Is Biodiesel?
    a. Biodiesel (Mono-Alkyl Esters)
    b. Non-Ester Renewable Diesel
    3. Does Renewable Fuel Include Motor Fuel That Is Made From 
Coprocessing a Renewable Feedstock With Fossil Fuels?
    a. Definition of ``Renewable Crudes'' and ``Renewable Crude-
Based Fuels''
    b. How Are Renewable Crude-Based Fuel Volumes Measured?
    4. What Are ``Equivalence Values'' for Renewable Fuel?
    a. Authority Under the Act To Establish Equivalence Values
    b. Energy Content and Renewable Content as the Basis for 
Equivalence Values
    c. Lifecycle Analyses as the Basis for Equivalence Values
    C. What Gasoline Is Used To Calculate the Renewable Fuel 
Obligation and Who Is Required To Meet the Obligation?
    1. What Gasoline Is Used To Calculate the Volume of Renewable 
Fuel Required To Meet a Party's Obligation?
    2. Who Is Required To Meet the Renewable Fuels Obligation?
    3. What Exemptions Are Available Under the RFS Program?
    a. Small Refinery and Small Refiner Exemption
    b. General Hardship Exemption
    c. Temporary Hardship Exemption Based on Unforeseen 
Circumstances
    4. What Are the Opt-in and State Waiver Provisions Under the RFS 
Program?
    a. Opt-in Provisions for Noncontiguous States and Territories
    b. State Waiver Provisions
    D. How Do Obligated Parties Comply With the Standard?
    1. Why Use Renewable Identification Numbers?
    a. RINs Serve the Purpose of a Credit Trading Program
    b. Alternative Approach To Tracking Batches
    2. Generating RINs and Assigning Them to Batches
    a. Form of Renewable Identification Numbers
    b. Generating RINs
    c. Cases in Which RINS Are Not Generated
    3. Calculating and Reporting Compliance
    a. Using RINs To Meet the Standard
    b. Valid Life of RINs
    c. Cap on RIN Use To Address Rollover
    d. Deficit Carryovers
    4. Provisions for Exporters of Renewable Fuel
    5. How Will the Agency Verify Compliance?
    E. How Are RINs Distributed and Traded?
    1. Distribution of RINs With Volumes of Renewable Fuel
    a. Responsibilities of Renewable Fuel Producers and Importers
    b. Responsibilities of Parties That Buy, Sell, or Handle 
Renewable Fuels
    c. Batch Splits and Batch Mergers
    2. Separation of RINs From Volumes of Renewable Fuel
    3. Distribution of Separated RINs
    4. Alternative Approaches to RIN Distribution
IV. Registration, Recordkeeping, and Reporting Requirements
    A. Introduction
    B. Registration
    1. Who Must Register Under the RFS Program?
    2. How Do I Register?
    3. How Do I Know I am Properly Registered With EPA?
    4. How are Small Volume Domestic Producers of Renewable Fuels 
Treated for Registration Purposes?
    C. Reporting
    1. Who Must Report Under the RFS Program?
    2. What Reports Are Required Under the RFS Program?
    3. What Are the Specific Reporting Items for the Various Types 
of Parties Required To Report?
    4. What are the Reporting Deadlines?
    5. How May I Submit Reports to EPA?
    6. What Does EPA Do With the Reports it Receives?
    7. May I Claim Information in Reports as CBI and How Will EPA 
Protect it?
    8. How are Spilled Volumes With Associated Lost RINs To Be 
Handled in Reports?
    D. Recordkeeping
    1. What Types of Records Must Be Kept?
    2. What Recordkeeping Requirements are Specific to Producers of 
Cellulosic or Waste-Derived Ethanol?
    E. Attest Engagements
    1. What Are the Attest Engagement Requirements Under the RFS 
Program?
    2. Who Is Subject to the Attest Engagement Requirements for the 
RFS Program?
    3. How Are the Attest Engagement Requirements in this Final Rule 
Different From Those Proposed?
V. What Acts Are Prohibited and Who Is Liable for Violations?
VI. Current and Projected Renewable Fuel Production and Use
    A. Overview of U.S. Ethanol Industry and Future Production/
Consumption
    1. Current Ethanol Production
    2. Expected Growth in Ethanol Production
    3. Current Ethanol and MTBE Consumption
    4. Expected Growth in Ethanol Consumption
    B. Overview of Biodiesel Industry and Future Production/
Consumption
    1. Characterization of U.S. Biodiesel Production/Consumption
    2. Expected Growth in U.S. Biodiesel Production/Consumption
    C. Feasibility of the RFS Program Volume Obligations
    1. Production Capacity of Ethanol and Biodiesel
    2. Technology Available To Produce Cellulosic Ethanol
    a. Sugar Platform
    i. Pretreatment
    ii. Dilute acid hydrolysis
    iii. Concentrated acid hydrolysis
    iv. Enzymatic hydrolysis
    b. Syngas Platform
    c. Plasma Technology
    d. Feedstock Optimization
    3. Renewable Fuel Distribution System Capability
VII. Impacts on Cost of Renewable Fuels and Gasoline
    A. Renewable Fuel Production and Blending Costs
    1. Ethanol Production Costs
    a. Corn Ethanol
    b. Cellulosic Ethanol
    2. Biodiesel Production Costs
    3. Diesel Fuel Costs
    B. Distribution Costs
    1. Ethanol Distribution Costs
    a. Capital Costs To Upgrade Distribution System for Increased 
Ethanol Volume
    b. Ethanol Freight Costs
    2. Biodiesel Distribution Costs
    C. Estimated Costs to Gasoline
    1. Description of Cases Modeled
    a. Base Case (2004)
    b. Reference Case (2012)
    c. Control Cases (2012)
    2. Overview of Cost Analysis Provided by the Contractor Refinery 
Model
    3. Overall Impact on Fuel Cost
    a. Cost Without Ethanol Subsidies
    b. Gasoline Costs Including Ethanol Consumption Tax Subsidies
VIII. What Are the Impacts of Increased Ethanol Use on Emissions and 
Air Quality?
    A. Effect of Renewable Fuel Use on Emissions
    1. Emissions From Gasoline Fueled Motor Vehicles and Equipment
    a. Gasoline Fuel Quality
    b. Emissions From Motor Vehicles
    c. Nonroad Equipment
    2. Diesel Fuel Quality: Biodiesel
    3. Renewable Fuel Production and Distribution
    B. Impact on Emission Inventories
    1. Primary Analysis
    2. Sensitivity Analysis
    3. Local and Regional VOC and NOX Emission Impacts in 
July
    C. Impact on Air Quality
    1. Impact of Increased Ethanol Use on Ozone
    2. Particulate Matter
IX. Impacts on Fossil Fuel Consumption and Related Implications
    A. Impacts on Lifecycle GHG Emissions and Fossil Energy Use
    1. Time Frame and Volumes Considered
    2. GREET Model
    a. Renewable Fuel Pathways Considered
    b. Modifications to GREET
    c. Sensitivity Analysis
    3. Displacement Indexes (DI)
    4. Impacts of Increased Renewable Fuel Use
    a. Greenhouse Gases and Carbon Dioxide
    b. Fossil Fuel and Petroleum
    B. Implications of Reduced Imports of Petroleum Products

[[Page 23902]]

    C. Energy Security Implications of Increases in Renewable Fuels
    1. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, 
and Economic Output
    2. Short-Run Disruption Premium From Expected Costs of Sudden 
Supply Disruptions
    3. Costs of Existing U.S. Energy Security Policies
X. Agricultural Sector Economic Impacts
XI. Public Participation
XII. Administrative Requirements
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    1. Overview
    2. Background
    4. Summary of Potentially Affected Small Entities
    5. Impact of the Regulations on Small Entities
    6. Small Refiner Outreach
    7. Reporting, Recordkeeping, and Compliance Requirements
    8. Related Federal Rules
    9. 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 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
    L. Clean Air Act Section 307(d)
XIII. Statutory A

I. Introduction

    Through today's final rule, we are putting in place a compliance 
and enforcement program that implements the renewable fuel program, 
also known as the Renewable Fuel Standard (RFS) program. This program 
accomplishes the statutory goal of increasing the volume of renewable 
fuels that are required to be used in vehicles in the U.S. as required 
in Section 211(o) of the Clean Air Act (CAA) enacted as part of the 
Energy Policy Act of 2005 (the Energy Act or the Act). This final rule 
resulted from a collaborative effort with stakeholders, including 
refiners, renewable fuel producers, and distributors, who together 
helped to design a program that is simple, flexible, and enforceable.
    As a result of the favorable economics of renewable fuels in 
comparison to conventional gasoline and diesel, renewable fuel volumes 
are expected to exceed the requirements of the RFS program. We have 
evaluated the impacts of a range of renewable fuel volumes as high as 
10 billion gallons in 2012. This represents a significant increase over 
the volume of renewable fuel used in 2004 which was approximately 3.5 
billion gallons, and this increase is estimated to produce a number of 
significant effects. For instance, we estimate that the transition to 
renewable fuels will reduce petroleum consumption by 2.0 to 3.9 billion 
gallons or approximately 0.8 to 1.6 percent of the petroleum that would 
otherwise be used by the transportation sector.
    The increased use of renewable fuels is also expected to produce 
reductions in some regulated pollutants. Carbon monoxide emissions from 
gasoline powered vehicles and equipment will be reduced by 0.9 to 2.5 
percent and emissions of benzene (a mobile source air toxic) will be 
reduced by 1.8 to 4.0 percent.\1\ At the same time, other emissions may 
increase. Nationwide, we estimate between a 41,000 and 83,000 ton 
increase in VOC + NOX emissions. However, the effects will 
vary significantly by region with some major metropolitan areas 
experiencing small emission benefits, while other areas may see an 
increase in VOC emissions from 4 to 5 percent and an increase in 
NOX emissions from 6 to 7 percent from gasoline powered 
vehicles and equipment.
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    \1\ These reductions are relative to the Mobile Source Air 
Toxics (MSAT) standards in effect. Additional benzene emission 
reductions will occur as a result of the recently finalized MSAT2 
standards (72 FR 8428, February 26, 2007).
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    The use of renewable fuel will likewise reduce greenhouse gas 
emissions such as carbon dioxide by 8.0 to 13.1 million metric tons, 
about 0.4 to 0.6 percent of the anticipated greenhouse gas emissions 
from the transportation sector in the United States in 2012. Greenhouse 
gas emissions contribute to climate change, and thus, increased 
renewable use is an important step in addressing this issue.
    Finally, we estimate that increases in the use of renewable fuels 
will increase net farm income and the nation's energy security. Net 
U.S. farm income is estimated to increase by between $2.6 and $5.4 
billion through transfers from users of gasoline and consumers of 
agricultural products used to produce ethanol. However, as feedstocks 
used in the production of renewable fuels expand beyond the corn and 
soybeans that are most common today, the renewable fuels industry is 
expected to continue to diversify and grow in its ability to benefit 
the nation's environment and economy.

A. The Role of Renewable Fuels in the Transportation Sector

    Renewable fuels have been an important part of our nation's 
transportation fuel supply for many years. Following the CAA amendments 
of 1990, the use of renewable fuels, particularly ethanol, increased 
dramatically. Several key clean fuel programs required by the CAA 
established new market opportunities for ethanol. A very successful 
mobile source control strategy, the reformulated gasoline (RFG) 
program, was implemented in 1995. This program set stringent new 
controls on the emissions performance of gasoline, which were designed 
to significantly reduce summertime ozone precursors and year round air 
toxics emissions. The RFG program also required that RFG meet an oxygen 
content standard. Several areas of the country began blending ethanol 
into gasoline to help meet this new standard, such as Chicago and St. 
Louis. Another successful clean fuel strategy required certain areas 
exceeding the national ambient air quality standard for carbon monoxide 
to also meet an oxygen content standard during the winter time to 
reduce harmful carbon monoxide emissions. Many of these areas, such as 
Denver and Phoenix, also blended ethanol during the winter months to 
help meet this new standard.
    Today, the role and importance of renewable fuels in the 
transportation sector continue to expand. In the past several years as 
crude oil prices have soared above the lower levels of the 1990's, the 
relative economics of renewable fuel use have improved dramatically. In 
addition, since the vast majority of crude oil produced in or imported 
into the U.S. is consumed as gasoline or diesel fuel in the U.S., 
concerns about our dependence on foreign sources of crude oil have 
renewed interest in renewable transportation fuels. The emergence of 
more in-depth understanding of the impacts of human activities on 
climate change has also focused attention on the various ways that 
renewable fuels can reduce the consumption of fossil fuels. The passage 
of the Energy Policy Act of 2005 demonstrated a strong commitment on 
the part of U.S. policymakers to consider additional means of 
supporting renewable fuels as a supplement to petroleum-based fuels in 
the transportation sector. The RFS program is one such means.
    The RFS program was debated by the U.S. Congress over several years 
before finally being enacted through passage of the Energy Policy Act 
of 2005. The RFS program is first and foremost designed

[[Page 23903]]

to increase the use of renewable fuels in motor vehicle fuel consumed 
in the U.S. In this context, it is expected to simultaneously reduce 
dependence on foreign sources of petroleum, increase domestic sources 
of energy, and diversify our energy portfolio to help transition to 
alternatives to petroleum in the transportation sector. Based on our 
analysis, we also believe that the expanded use of renewable fuels will 
provide reductions in carbon dioxide emissions that contribute to 
climate change and in air toxics emissions such as benzene from the 
transportation sector, while other emissions such as hydrocarbons and 
oxides of nitrogen are projected to increase. The increased use of 
renewable fuels such as ethanol and biodiesel is also expected to have 
the added effect of providing an expanded market for agricultural 
products such as corn and soybeans. The expected increase in cellulosic 
ethanol production will also expand the market opportunities to a wider 
array of feedstocks.
    The requirement for use of a specified volume of renewable fuels 
complements other provisions of the Energy Act. In particular, the 
required volume of renewable fuel use will offset any possible loss in 
demand for renewable fuels occasioned by the Act's repeal of the oxygen 
content mandate in the RFG program while allowing greater flexibility 
in how renewable fuels are blended into the nation's fuel supply. The 
RFS program also creates a specific annual level for minimum renewable 
fuel use which increases over time, ensuring overall growth in the 
demand and opportunity for renewable fuels.
    Because renewable fuels such as ethanol and biodiesel are not new 
to the U.S. transportation sector, the expansion of their use is 
expected to follow distribution and blending practices already in 
place. For instance, the market already has the necessary production 
and distribution mechanisms in place in many areas and the ability to 
expand these mechanisms into new markets. Recent spikes in ethanol use 
resulting first from the state MTBE bans, and now the virtual 
elimination of MTBE from the marketplace, have tested the limits of the 
ethanol distribution system. However, future growth is expected to move 
in a more orderly fashion since the use of renewable fuels will not be 
geographically constrained and, given EIA volume projections, 
investment decisions can follow market forces rather than regulatory 
mandates. In addition, the increased production volumes of ethanol and 
the expanded penetration of ethanol in new markets may create new 
opportunities for blending of E85, a blend of 85 percent ethanol and 15 
percent gasoline, in the long run. The increased availability of E85 
will mean that more flexible fueled vehicles (FFV) can use this fuel. 
Of the approximately 5 million FFVs currently in use in the U.S, most 
are currently fueled with conventional gasoline rather than E85, in 
part due to the limited availability of E85.
    Given the ever-increasing demand for petroleum-based products in 
the transportation sector, the RFS program also moves the nation in the 
direction of replacing part of this demand with renewable energy. The 
RFS program provides the certainty that at least a minimum amount of 
renewable fuel will be used in the U.S., which in turn provides some 
certainty for investment in production capacity of renewable fuels. 
However, it should be understood that the RFS program is not the only 
factor currently impacting demand for ethanol and other renewable 
fuels. As Congress was developing the RFS program in the Energy Act, 
several large states were adopting and implementing bans on the use of 
MTBE in gasoline. As a result, refiners supplying reformulated gasoline 
(RFG) in those states switched to ethanol to satisfy the oxygen content 
mandate for their RFG, causing a large, sudden increase in demand for 
ethanol. Even more importantly, with the removal of the oxygen content 
mandate for RFG, refiners elected to remove essentially all MTBE from 
the gasoline supply in the U.S. during the spring of 2006. In order to 
accomplish this transition quickly, while still maintaining gasoline 
volume, octane, and gasoline air toxics performance standards, refiners 
elected to blend ethanol into virtually all reformulated gasoline 
nationwide. This caused a second dramatic increase in demand for 
ethanol, which in the near term was met by temporarily shifting large 
volumes of ethanol out of conventional gasoline and into the RFG areas.
    Perhaps the largest impact on renewable fuel demand, however, has 
been the increase in the cost of crude oil. In the last few years, both 
crude oil prices and crude oil price forecasts have increased 
dramatically. This has resulted in a large economic incentive for the 
use of ethanol and biodiesel. The Energy Information Administration 
(EIA) and others are currently projecting renewable fuel demand to 
exceed the minimum volumes required under the RFS program by a 
substantial margin. In this context, the effect of the RFS program is 
to provide a minimum level of demand to support ongoing investment in 
renewable fuel production. However, market demand for renewable fuels 
is expected to exceed the statutory minimums. We believe that the 
program we are finalizing today will operate effectively regardless of 
the level of renewable fuel use or market conditions in the energy 
sector.

B. Requirements in the Energy Policy Act

    Section 1501 of the Energy Policy Act amended the Clean Air Act and 
provides the statutory basis for the RFS program in Section 211(o). It 
requires EPA to establish a program to ensure that the pool of gasoline 
sold in the contiguous 48 states contains specific volumes of renewable 
fuel for each calendar year starting with 2006. The required overall 
volumes for 2006 through 2012 are shown in Table I.B-1 below.

    Table I.B-1.-- Applicable Volumes of Renewable Fuel Under the RFS
                                 Program
------------------------------------------------------------------------
                                                                Billion
                        Calendar year                           gallons
                                                                  2006
------------------------------------------------------------------------
2006.........................................................        4.0
2007.........................................................        4.7
2008.........................................................        5.4
2009.........................................................        6.1
2010.........................................................        6.8
2011.........................................................        7.4
2012.........................................................        7.5
------------------------------------------------------------------------

    In order to ensure the use of the total renewable fuel volume 
specified for each year, the Agency must set a standard for each year 
representing the amount of renewable fuel that each refiner, blender, 
or importer must use, expressed as a percentage of gasoline sold or 
introduced into commerce. This yearly percentage standard is to be set 
at a level that will ensure that the total renewable fuel volumes shown 
in Table I.B-1 will be used based on gasoline volume projections 
provided by the Energy Information Administration (EIA). The standard 
for each year must be published in the Federal Register by November 30 
of the previous year. Starting with 2013, EPA is required to establish 
the applicable national volume, based on the criteria contained in the 
statute, which must require at least the same overall percentage of 
renewable fuel use as was required in 2012.
    The Act defines renewable fuels primarily on the basis of the 
feedstock. In general, renewable fuel must be a motor vehicle fuel that 
is produced from plant or animal products or wastes, as opposed to 
fossil fuel sources. The Act

[[Page 23904]]

specifically identifies several types of motor vehicle fuels as 
renewable fuels, including cellulosic biomass ethanol, waste-derived 
ethanol, biogas, biodiesel, and blending components derived from 
renewable fuel.
    The standard set annually by EPA is to be a single percentage 
applicable to refiners, blenders, and importers, as appropriate. The 
percentage standard is used by obligated parties to determine a volume 
of renewable fuel that they are responsible for introducing into the 
domestic gasoline pool for the given year. The percentage standard must 
be adjusted such that it does not apply to multiple parties for the 
same volume of gasoline. The standard must also take into account the 
use of renewable fuel by small refineries that are exempt from the 
program until 2011.
    Under the Act, the required volumes in Table I.B-1 apply to the 
contiguous 48 states. However, Alaska and Hawaii can opt into the 
program, in which case the pool of gasoline used to calculate the 
standard, and the number of regulated parties, would change. In 
addition, other states can request a waiver of the RFS program under 
certain conditions, which would affect the national quantity of 
renewable fuel required under the program.
    The Act requires the Agency to promulgate a credit trading program 
for the RFS program whereby an obligated party may generate credits for 
over-complying with their annual obligation. The obligated party can 
then use these credits to meet their requirements in the following year 
or trade them for use by another obligated party. Thus the credit 
trading program allows obligated parties to comply in the most cost-
effective manner by permitting them to generate, transfer, and use 
credits. The trading program also permits renewable fuels that are not 
blended into gasoline, such as biodiesel, to participate in the RFS 
program.
    The Agency must determine who can generate credits, under what 
conditions credits may be traded, how credits may be transferred from 
one party to another, and the appropriate value of credits for 
different types of renewable fuel. If a party is not able to generate 
or purchase sufficient credits to meet their annual obligation, they 
are allowed to carry over the deficit to the next annual compliance 
period, but must achieve full compliance in that following year.

C. Development of the RFS Program

    Section 1501 of the Energy Act prescribed the RFS program, 
including the required total volumes, the timing of the obligation, the 
parties who are obligated to comply, the definition of renewable fuel, 
and the general framework for a credit trading program. Various aspects 
of the program require additional development by the Agency beyond the 
specifications in the Act. The Agency must develop regulations to 
ensure the successful implementation of the RFS program, based on the 
framework spelled out in the statute.
    Under the RFS program the trading provisions comprise an integral 
element of compliance. Many obligated parties do not have access to 
renewable fuels or the ability to blend them, and so must use credits 
to comply. The RFS trading program is also unique in that the parties 
liable for meeting the standard (refiners, importers, and blenders of 
gasoline) are not generally the parties who make the renewable fuels or 
blend them into gasoline. This creates the need for trading mechanisms 
that ensure that the means to demonstrate compliance will be readily 
available for use by obligated parties.
    The first step we took in developing the proposed program was to 
seek input and recommendations from the affected stakeholders. There 
were initially a wide range of thoughts and views on how to design the 
program. However, there was broad consensus that the program should 
satisfy a number of guiding principles, including, for example, that 
the compliance and trading program should provide certainty to the 
marketplace and minimize cost to the consumers; that the program should 
preserve existing business practices for the production, distribution, 
and use of both conventional and renewable fuels; that the program 
should be designed to accommodate all qualifying renewable fuels; that 
all renewable volumes produced are made available to obligated parties 
for compliance; and that the Agency should have the ability to easily 
verify compliance to ensure that the volume obligations are in fact 
met. These guiding principles and the comments we received on our 
Notice of Proposed Rulemaking (NPRM) helped to move us toward the 
program in today's final rule.
    We published a Notice of Proposed Rulemaking on September 22, 2006 
(71 FR 55552) which described our proposed approach to compliance and 
the trading program, as well as preliminary analyses of the 
environmental and economic impacts of increased use of renewable fuels. 
The program finalized today largely mirrors the proposed program, with 
some revisions reflecting continued input from stakeholders during the 
formal comment period.

II. Overview of the Program

    Today's action establishes the final requirements for the RFS 
program, as well as our assessment of the environmental and economic 
impacts of the nation's transition to greater use of renewable fuels. 
This section provides an overview of our program and renewable fuel 
impacts assessment. Sections III through V provide the details of the 
structure of the program, while Sections VI through X describe our 
assessment of the impacts on emissions of regulated pollutants and 
greenhouse gases, air quality, fossil fuel use, energy security, 
economic impacts in the agricultural sector, and cost from the expanded 
use of renewable fuels.

A. Impacts of Increased Reliance on Renewable Fuels

    In a typical major rulemaking, EPA would conduct a full assessment 
of the economic and environmental impacts of the specific rule that it 
is promulgating. However, as discussed in Section I.A., the replacement 
of MTBE with ethanol and the extremely favorable economics for 
renewable fuels brought on by the rise in crude oil prices are causing 
renewable fuel use to far exceed the RFS requirements. Given these 
circumstances, it is important to assess the impacts of this larger 
increase in renewable use and the related changes occurring to 
gasoline. For this reason we have carried out an assessment of the 
economic and environmental impacts of the broader changes in fuel 
quality resulting from our nation's transition to greater utilization 
of renewable fuels, as opposed to an assessment that is limited to the 
RFS program itself.
    To carry out our analyses, we elected to use 2004 as the baseline 
from which to compare the impacts of expanded renewable use. We chose 
2004 as a baseline primarily due to the fact that all the necessary 
refinery production data, renewable fuel production data, and fuel 
quality data were already in hand at the time we needed to begin the 
analysis. We did not use 2005 as a baseline year because 2005 may not 
be an appropriate year for comparison due to the extraordinary impacts 
of hurricanes Katrina and Rita on gasoline production and use. To 
assess the impacts of anticipated increases in renewable fuels, we 
elected to look at what they would be in 2012, the year the 
statutorily-mandated renewable fuel volumes will be fully phased in. By 
conducting the analysis in this manner, the impacts include not just 
the impact of expanded renewable fuel use by itself, but also the 
corresponding decrease in the use of MTBE, and the

[[Page 23905]]

potential for oxygenates to be removed from RFG due to the absence of 
the RFG oxygenate mandate. Since these three changes are all 
inextricably linked and are occurring simultaneously in the 
marketplace, evaluating the impacts in this manner is both necessary 
and appropriate.
    We evaluated the impacts of expanded renewable fuel use and the 
corresponding changes to the fuel supply on fuel costs, consumption of 
fossil fuels, and some of the economic impacts on the agricultural 
sector and energy security. We also evaluated the impacts on emissions, 
including greenhouse gas emissions that contribute to climate change, 
and the corresponding impacts on nationwide and regional air quality. 
Our analyses are summarized in this section.
1. Renewable Fuel Volume Scenarios Analyzed
    As shown in Table I.B-1, the Act stipulates that the nationwide 
volumes of renewable fuel required under the RFS program must be at 
least 4.0 billion gallons in 2006 and increase to 7.5 billion gallons 
in 2012. However, we expect that the volume of renewable fuel will 
actually exceed the required volumes by a significant margin. Based on 
economic modeling in 2006, EIA projected renewable fuel demand in 2012 
of 9.6 billion gallons for ethanol, and approximately 300 million 
gallons for biodiesel using crude oil prices forecast at $48 per 
barrel.\2\ Therefore, in assessing the impacts of expanded use of 
renewable fuels, we evaluated two comparative scenarios, one 
representing the statutorily required minimum, and another reflecting 
the higher levels projected by EIA. Although the actual renewable fuel 
volumes produced in 2012 may differ from both the required and 
projected volumes, we believe that these two volume scenarios together 
represent a reasonable range for analysis purposes.\3\
---------------------------------------------------------------------------

    \2\ $48/barrel from Annual Energy Outlook 2006, Energy 
Information Administration, Department of Energy.
    \3\ Subsequent to the analysis for this final rule, EIA has 
released its 2007 AEO forecasts for ethanol use, which increase the 
projection to 11.2 billion gallons by 2012.
---------------------------------------------------------------------------

    The Act also stipulates that at least 250 million gallons out of 
the total volume required in 2013 and beyond must meet the definition 
specified for cellulosic biomass ethanol. As described in Section VI, 
there are a number of companies already making plans to produce ethanol 
from cellulosic feedstocks and/or waste-derived energy sources that 
could potentially meet the definition of cellulosic biomass ethanol. 
Accordingly, we anticipate a ramp-up in production of cellulosic 
biomass ethanol production in the coming years, and for analysis 
purposes we have assumed that 250 million gallons of cellulosic biomass 
ethanol will be used in 2012.
    As discussed in Section VI, we chose 2004 to represent current 
baseline conditions. However, a direct comparison of the fuel quality 
impacts on emissions and air quality that are expected to occur once 
the RFS program is fully phased in required that changes in overall 
fuel volume, fleet characterization, and other factors be constant. 
Therefore, we created a 2012 reference case from the 2004 base case for 
use in the emissions and air quality analysis that maintained current 
fuel quality parameters while incorporating forecasted increases in 
vehicle miles traveled and changes in fleet demographics. The 2012 fuel 
reference case was developed by growing out the 2004 renewable fuel 
baseline according to EIA's forecasted energy growth rates between 2004 
and 2012.
    For the analyses, we created two 2012 scenarios representing 
expanded renewable fuel production. The ``RFS Case'' represents volume 
levels designed to exactly meet the requirements of the RFS program, 
and includes the effects of higher credit values for cellulosic ethanol 
and biodiesel. Since higher credit values mean that one gallon of 
renewable fuel counts as more than one gallon for compliance purposes, 
less than 7.5 billion gallons of renewable fuel is needed to meet the 
7.5 billion gallon statutory requirement, but credits equivalent to 7.5 
billion gallons of renewable fuel would still be available for 
compliance purposes. The ``EIA Case'' represents volume levels based on 
EIA projections. A summary of the assumed renewable fuel volumes for 
the scenarios we evaluated is shown in Table II.A.1-1. Details of the 
calculations used to determine these volumes are given in Chapter 2 of 
the Regulatory Impact Analysis (RIA) in the docket for this rulemaking.

                       Table II.A.1-1.--Renewable Fuel Volume Scenarios (Billion Gallons)
----------------------------------------------------------------------------------------------------------------
                                                                                             2012
                                                                  2004  base -----------------------------------
                                                                     case      Reference
                                                                                 case      RFS case    EIA case
----------------------------------------------------------------------------------------------------------------
Corn-ethanol....................................................       3.548       3.947       6.421       9.388
Cellulosic ethanol..............................................       0           0           0.25        0.25
Biodiesel.......................................................       0.025       0.030       0.303       0.303
                                                                 -----------------------------------------------
    Total volume................................................       3.573       3.977       6.974       9.941
----------------------------------------------------------------------------------------------------------------

2. Emissions
    We evaluated the impacts of increased use of ethanol and biodiesel 
on emissions and air quality in the U.S. relative to the reference 
case. We estimated that nationwide VOC emissions in 2012 from gasoline 
vehicles and equipment will increase by about 0.3% in the RFS Case and 
about 0.7% in the EIA Case. For NOX, we estimated that 
nationwide annual emissions in 2012 will increase about 0.9% for the 
RFS Case and 1.6% for the EIA Case. These increases are equivalent to 
an additional 18,000 to 43,000 tons of VOC per year, and an additional 
23,000 to 40,000 tons of NOX per year.
    We also estimated the change in emissions in those areas which are 
projected to experience a significant change in ethanol use; i.e., 
where the market share of ethanol blends was projected to change by 50 
percent or more. We focused on July emissions since these are most 
relevant to ozone formation and modeled 2015 because our ozone model is 
based upon a 2015 emissions inventory (though we would expect similar 
results in 2012). Finally, we developed separate estimates for RFG 
areas, low RVP areas (i.e., RVP standards less than 9.0 RVP), and 
conventional gasoline areas with a summer 9.0 RVP standard. For areas 
with a significant change in ethanol use,

[[Page 23906]]

compared to the reference case, VOC emissions in RFG areas increased by 
up to 2.3%, while NOX emissions increased by up to 1.6%. In 
low RVP areas, VOC emissions increased by up to 4.6%, while 
NOX emissions increased by up to 6.2%. In 9.0 RVP areas, VOC 
emissions increased by up to 4.6%, while NOX emissions 
increased by up to 7.3%.
    Unlike VOC and NOX, emissions of CO and benzene from 
gasoline vehicles and equipment were estimated to decrease in 2012 when 
the use of renewable fuels increased. Reductions in emissions of CO 
varied from 0.9% percent to as high as 2.5% percent for the nation as a 
whole, depending on the renewable fuel volume scenario. Similarly, 
benzene emissions from gasoline vehicles and equipment were estimated 
to be reduced from 1.8% to 4.0% percent.
    We do not have sufficient data to predict the effect of ethanol use 
on levels of either directly emitted particulate matter (PM) or 
secondarily formed PM. The increased NOX emissions are 
expected to lead to increases in secondary nitrate PM, but at the same 
time reduced aromatics resulting from ethanol blending are likely to 
lead to a decrease in secondary organic PM, as discussed in Section 
VIII.C. In addition, biodiesel use is expected to result in some 
reduction in direct PM emissions, though small in magnitude due to the 
relatively small volumes.
    The emission impact estimates described above are based on the best 
available data and models. However, it must be highlighted that most of 
the fuel effect estimates are based on very limited or old data which 
may no longer be reliable in estimating the emission impacts on 
vehicles in the 2012 fleet with advanced emission controls.\4\ As such, 
these emission estimates should be viewed as preliminary. EPA hopes to 
conduct significant new testing in order to better estimate the impact 
of fuel changes on emissions from both highway vehicles and nonroad 
equipment, including those fuel changes brought about by the use of 
renewable fuels. We hope to be able to incorporate the data from such 
additional testing into the analyses for other studies required by the 
Energy Act, and into a subsequent rule to set the RFS program standard 
for 2013 and later.
---------------------------------------------------------------------------

    \4\ Advanced emission controls include close-coupled, high-
density catalysts and their associated electronic control systems 
for light-duty vehicles, and NOX adsorbers and PM traps 
for heavy-duty engines.
---------------------------------------------------------------------------

    We used the Ozone Response Surface Model (RSM) to estimate the 
impacts of the increased use of ethanol on ozone levels for both the 
RFS Case and the EIA Case. The ozone RSM approximates the effect of VOC 
and NOX emissions in a 37-state eastern area of the U.S. 
Using this model, we projected that the changes in VOC and 
NOX emissions could produce a very small increase in ambient 
ozone levels. On average, population-weighted ozone design value 
concentrations increased by about 0.05 ppb, which represents 0.06 
percent of the standard. Even for areas expected to experience a 
significant increase in ethanol use, population-weighted ozone design 
value concentrations increased by only 0.15 to 0.18 ppb, about 0.2 
percent of the standard. These ozone impacts do not consider the 
reductions in CO emissions mentioned above, or the change in the types 
of compounds comprising VOC emissions. Directionally, both of these 
factors may mitigate these ozone increases.
    We investigated several other issues related to emissions and air 
quality that could affect our estimates of the impacts of increased use 
of renewable fuels. These are discussed in Section VIII and in greater 
detail in the RIA. For instance, our current models assume that recent 
model year vehicles are insensitive to many fuel changes. However, a 
limited amount of new test data suggest that newer vehicles may be just 
as sensitive as older model year vehicles. Our sensitivity analysis 
suggests that if this is the case, VOC emissions could decrease by as 
much as 0.3%, instead of increasing by up to 0.7%. NOX 
emissions could increase by up to 4.2%, up from a 1.6% increase. We 
also evaluated the emissions from the production of both ethanol and 
biodiesel fuel and determined that they will also increase with 
increased use of these fuels. Nationwide, emissions related to the 
production and distribution of ethanol and biodiesel fuel are projected 
to be of the same order of magnitude as the emission impacts related to 
the use of these fuels in vehicles.
    Finally, a lack of emission data and atmospheric modeling tools 
prevented us from making specific projections of the impact of 
renewable fuels on ambient PM levels. As mentioned, however, ethanol 
use may affect ambient PM levels due to the increase in NOX 
emissions and the reduction in the aromatic content of gasoline, which 
should reduce aromatic VOC emissions. All of these issues will be the 
subject of further study and analysis in the future.
3. Economic Impacts
    In Section VII of this preamble, we estimate the cost of producing 
the extra volumes of renewable fuel anticipated through 2012. For corn 
ethanol, we estimate the per gallon cost of ethanol to range from $1.26 
per gallon in 2012 (2004 dollars) in the RFS Case to $1.32 per gallon 
in the EIA Case. These costs take into account the cost of the 
feedstock (corn), plant equipment and operation and the value of any 
co-products (distiller's dried grain and solubles, for example). For 
biodiesel, we estimate the per gallon cost to be between $1.89 and 
$2.06 per gallon if produced using soy bean oil, and less if using 
yellow grease ($1.11 to $1.56 per gallon) or other relatively low cost 
or no-cost feedstocks. The price paid for ethanol, however, is reduced 
by the $0.51 per gallon federal tax subsidy as well as any state 
subsidies that might apply. Similarly the price paid for biodiesel is 
reduced due to the $1.00 per gallon federal tax subsidy biodiesel 
produced from soy bean oil and $0.50 per gallon tax subsidy for 
biodiesel produced from yellow grease. We also note that these costs 
represent the production cost of the fuel and not the market price. In 
recent years, the prices of ethanol and biodiesel have tended to track 
the prices of gasoline and diesel fuel, in some cases even exceeding 
those prices.
    These renewable fuels are then blended in gasoline and diesel fuel. 
While biodiesel is typically just blended with typical petroleum 
diesel, additional efforts are sometimes necessary and/or economically 
advantageous at the refiner level when adding ethanol to gasoline. For 
example, ethanol's high octane reduces the need for other octane 
enhancements by the refiner, whereas offsetting the volatility increase 
caused by ethanol may require removal of other highly volatile 
components. Section VII examines these fuel cost impacts and concludes 
that the net cost to society in 2012 in comparison to the reference 
case will range from an estimate of 0.5 cent to 1.0 cent per gallon of 
gasoline due to the increased use of renewable fuels and their 
displacement of MTBE. The resulting total nationwide costs in 2012 are 
$823 million per year for the RFS case and $1,739 million per year for 
the EIA case. This total excludes the effects of the 51 cent/gal 
federal excise tax credit as well as state tax subsidies.
    Our estimates of fuel impacts do not consider other societal 
benefits. For example, the displacement of petroleum-based fuel 
(largely imported) by renewable fuel (largely produced in the United 
States), should reduce our use of imported oil and fuel. We estimate 
that 95 percent of the lifecycle petroleum reductions resulting from 
the use of renewable fuel will be met

[[Page 23907]]

through reductions in net petroleum imports. In Section IX of this 
preamble we estimate the value of the decrease in imported petroleum at 
about $2.6 billion in 2012 for the RFS Case and $5.1 billion for the 
EIA Case, in comparison to our 2012 reference case. Total petroleum 
import expenditures in 2012 are projected to be about $698 billion.
    Furthermore, the above estimate on reduced petroleum import 
expenditures only partly assess the economic impacts. One of the 
effects of increased use of renewable fuel is that it diversifies the 
energy sources used in making transportation fuel. To the extent that 
diverse sources of fuel energy reduce the dependence on any one source, 
the risks, both financial as well as strategic, of a potential 
disruption in supply reflected in the price volatility of a particular 
energy source are reduced. As indicated in the proposal, EPA has worked 
with researchers at Oakridge National Laboratory to update a study they 
previously published and which has been used or cited in several 
government actions impacting oil consumption. A draft report is being 
made available in the docket at this time for further consideration. 
This analysis only looks at the impact of reduced petroleum imports on 
energy security. Other energy security issues could arise with the 
wider use of biofuels. For example, ethanol's production and costs are 
determined by the availability of corn as a feedstock. Corn production, 
in turn, is weather-dependent. Also, the use of biofuels may increase 
the use of natural gas. A full integrated analysis of the energy 
security implications of the wider use of biofuels has yet to be 
undertaken.
    While increased use of renewable fuel will reduce expenditures on 
imported oil, it will also increase expenditures on renewable fuels and 
in-turn, on the sources of those renewable fuels. The RFS program 
attempts to spur the increased use of renewable transportation fuels 
made principally from agricultural crops produced in the U.S. As a 
result, it is important to analyze the consequences of the transition 
to greater renewable fuel use in the U.S. agricultural sector. To 
perform this analysis, EPA selected the Forest and Agricultural Sector 
Optimization Model (FASOM) developed by Professor Bruce McCarl of Texas 
A&M University and others over the past thirty years. FASOM is a 
dynamic, nonlinear programming model of the agriculture and forestry 
sectors of the U.S. (For this analysis, we focused on the agriculture 
portion of the model.)
    Due to the greater demand for corn as a feedstock for ethanol 
production, corn prices are estimated to increase in 2012 by 18 cents 
per bushel for the RFS Case and 39 cents per bushel of corn for the EIA 
Case from $2.32 (in 2004 dollars) in the Reference Case. Although 
soybean prices are expected to rise slightly, the increased cost is 
likely due to higher input costs, such as land prices. We estimate a 
price increase of 18 cents (RFS Case) to 21 cents (EIA Case) per bushel 
of soybeans from a Reference Case price of $5.26 per bushel. These 
higher commodity prices are predicted to also result in higher U.S. 
farm income. Our analysis predicts that farm income will increase by 
$2.6 billion annually by 2012 for the RFS Case and $5.4 billion for the 
EIA Case, roughly a 5 to 10 percent increase.
    Due to higher corn prices, U.S. exports of corn are estimated to 
decrease by $573 million in the RFS Case and by $1.29 billion in the 
EIA Case in 2012. With higher commodity prices, we would expect some 
upward pressure on food costs as the higher cost of corn and soybeans 
is passed along to consumers. We estimate a relatively modest increase 
in annual household food costs associated with the higher price 
commanded by corn and soybeans. For the RFS Case, annual per capita 
wholesale food cost are estimated to increase by approximately $7, 
while the higher renewable fuel volumes anticipated by the EIA Case 
will result in a $12 annual increase in the per capita wholesale food 
cost. This equates to roughly a $2.1 to $3.6 billion increase in 
nationwide food costs in 2012.
4. Greenhouse Gases and Fossil Fuel Consumption
    There has been considerable interest in the impacts of fuel 
programs on greenhouse gases implicated in climate change and on fossil 
fuel consumption due largely to concerns about dependence on foreign 
sources of petroleum. Therefore, in this rulemaking we have undertaken 
an analysis of the greenhouse gas and fossil fuel consumption impacts 
of a transition to greater renewable fuel use. This is the first 
analysis of its kind in a high profile rule, and as such it may guide 
future work in this area.
    As a result of the transition to greater renewable fuel use, some 
petroleum-based gasoline and diesel will be directly replaced by 
renewable fuels. Therefore, consumption of petroleum-based fuels will 
be lower than it would be if no renewable fuels were used in 
transportation vehicles. However, a true measure of the impact of 
greater use of renewable fuels on petroleum use, and indeed on the use 
of all fossil fuels, accounts not only for the direct use and 
combustion of the finished fuel in a vehicle or engine, but also 
includes the petroleum use associated with production and 
transportation of that fuel. For instance, fossil fuels are used in 
producing and transporting renewable feedstocks such as plants or 
animal byproducts, in converting the renewable feedstocks into 
renewable fuel, and in transporting and blending the renewable fuels 
for consumption as motor vehicle fuel. Likewise, fossil fuels are used 
in the production and transportation of petroleum and its finished 
products. In order to estimate the true impacts of increases in 
renewable fuel use on fossil fuel use, we must take these steps into 
account. Such analyses are termed lifecycle analyses.
    There is also no consensus on the most appropriate approach for 
conducting such lifecycle analyses. We have chosen to base our 
lifecycle analysis on Argonne National Laboratory's GREET model for the 
reasons described in Section IX. However, there are other lifecycle 
models in use. The choice of model inputs and assumptions all have a 
bearing on the results of lifecycle analyses, and many of these 
assumptions remain the subject of debate among researchers.
    With these caveats, we compared the lifecycle impacts of renewable 
fuels to the petroleum-based gasoline and diesel fuels that they 
replace. This analysis allowed us to estimate not only the overall 
impacts of renewable fuel use on petroleum use, but also on emissions 
of greenhouse gases such as carbon dioxide from all fossil fuels. In 
comparison to the reference case, we estimate that the increased use of 
renewable fuels in the RFS and EIA cases will reduce transportation 
sector petroleum consumption by about 0.8 and 1.6 percent, 
respectively, in the transportation sector in 2012. This is equivalent 
to 2.0-3.9 billion gallons of petroleum in 2012. We also estimated that 
greenhouse gases from the transportation sector will be reduced by 
about 0.4 and 0.6 percent for the RFS and EIA cases, respectively, 
equivalent to about 8-13 million metric tons. These reductions are 
projected to continue to increase beyond 2012 since crude oil prices 
have been projected by EIA to continue to be high relative to the 
prices of the 1990's, and as a result there is expected to be an 
economic advantage to using renewable fuels beyond 2012. These 
greenhouse gas emission reductions are also highly dependent on the 
expectation that the majority of the future ethanol use will be 
produced

[[Page 23908]]

from corn. If advances in the technology for converting cellulosic 
feedstocks into ethanol allow cellulosic ethanol use to exceed the 
levels assumed in our analysis, then even greater greenhouse gas 
reductions may result.\5\
---------------------------------------------------------------------------

    \5\ Cellulosic ethanol is estimated to provide a comparable 
petroleum displacement as corn derived ethanol on a per gallon 
basis, though the impacts on total energy and greenhouse gas 
emissions differ.
---------------------------------------------------------------------------

5. Post 2012 RFS Standards
    The Energy Policy Act of 2005, in addition to setting the standards 
to be adopted through 2012, requires EPA, in coordination with the 
Departments of Agriculture and Energy, to determine the applicable 
volume for the renewable fuel standard for the year 2013 and subsequent 
calendar years. This determination is to be based on a review of the 
program's implementation in 2006 through 2012 as well as review of the 
impact of renewable fuels on the environment, air quality, energy 
security, job creation, rural economic development and the expected 
annual rate of renewable fuel production, including production of 
cellulosic ethanol.
    In today's final rulemaking, we do not suggest any specific 
renewable fuel volumes for 2013 and beyond that may be appropriate 
under the statutory criteria. However, we would note that the 
President, in his State of the Union address this January, set specific 
goals reducing the amount of gasoline usage in the United States by 20 
percent in the next 10 years. This would be accomplished by reforming 
and modernizing fuel economy standards for cars and setting mandatory 
fuels standard equivalent to requiring use of 35 billion gallons of 
renewable and alternative \6\ fuels in 2017. Therefore, given the 
necessity to address the post-2013 period under the Energy Act and the 
prospect of continued attention by the Administration and Congress to 
this issue, EPA will continue to devote attention to the issue of 
renewable and alternative fuel volumes in the post-2013 period.
---------------------------------------------------------------------------

    \6\ While the RFS program is specific to renewable fuels, the 
president's goal of 35 billion gallons by 2017 would include not 
only renewable fuels, but also other types of alternatives fuels.
---------------------------------------------------------------------------

    From a program structure perspective, we believe that what we are 
putting in place today will remain useful as part of a 2013 and later 
program. For example, EPA considers that the identification of 
renewable fuel via a Renewable Identification Number (RIN), the 
determination of liable parties, the averaging, banking and trading 
system and the recordkeeping and reporting system would all be elements 
of a post-2013 program. Depending on the structure of any final 
legislation approved by Congress and signed into law, such elements 
could also be incorporated into an expanded renewable and alternative 
fuels program.

B. Program Structure

    The RFS program being finalized today requires refiners, importers, 
and blenders (other than oxygenate blenders) to show that a required 
volume of renewable fuel is used in gasoline. The required volume is 
determined by multiplying their annual gasoline production by a 
percentage standard specified by EPA. Compliance is demonstrated 
through the acquisition of unique Renewable Identification Numbers 
(RINs) assigned by the producer or importer to every batch of renewable 
fuel produced or imported. The RIN shows that a certain volume of 
renewable fuel was produced or imported. Each year, the refiners, 
blenders and importers obligated to meet the renewable volume 
requirement (referred to as ``obligated parties'') must acquire 
sufficient RINs to demonstrate compliance with their volume obligation. 
RINs can be traded, thereby functioning as the credits envisioned in 
the Act. A system of recordkeeping and electronic reporting for all 
parties that have RINs ensures the integrity of the RIN pool. This RIN-
based system will both meet the requirements of the Act and provide 
several other important advantages:
     Renewable fuel production volumes can be easily verified.
     RIN trading can occur in real time as soon as the 
renewable fuel is produced rather than waiting to the end of the year 
when an obligated party would determine if it had exceeded the 
standard.
     Renewable fuel can continue to be produced, distributed, 
and blended in those markets where it is most economical to do so.
     Instances of double-counting of renewable fuel claimed for 
compliance purposes can be identified based on electronically reported 
data.
    Our RIN-based trading program is an essential component of the RFS 
program, ensuring that every obligated party can comply with the 
standard while providing the flexibility for each obligated party to 
use renewable fuel in the most economical ways possible.
1. What Is the RFS Program Standard?
    EPA is required to convert the aggregate national volumes of 
renewable fuel specified in the Act into corresponding renewable fuel 
standards expressed as a percent of gasoline production or importation. 
The renewable volume obligation that will apply to an individual 
obligated party will then be determined based on this percentage and 
the total gasoline production or import volume in a calendar year, 
January 1 through December 31. EPA will publish the percentage standard 
in the Federal Register each November for the following year based on 
the most recent EIA gasoline demand projections. However, for 
compliance in 2007 we are publishing the percentage standard in today's 
action. The standard for 2007 is 4.02 percent. Section III.A describes 
the calculation of the standard.
2. Who Must Meet the Standard?
    Under our program, any party that produces or imports gasoline for 
consumption in the U.S., including refiners, importers, and blenders 
(other than oxygenate blenders), will be subject to a renewable volume 
obligation that is based on the renewable fuel standard. These 
obligated parties will determine the level of their obligation by 
multiplying the percentage standard by their annual volume of gasoline 
production or importation. The result will be the renewable fuel volume 
which each party must ensure is blended into gasoline consumed in the 
U.S., with credit for certain other renewable fuels that are not 
blended into gasoline.
    For 2007, we are requiring that the renewable fuel volume 
obligation be determined by multiplying the percentage standard by the 
volume of gasoline produced or imported prospectively from September 1, 
2007 until December 31, 2007. While the standard will not apply to all 
of 2007 gasoline production, we are nevertheless confident that the 
total volume of renewable fuel used in all of 2007 will still exceed 
the volume specified in the Act due to expectations that the demand for 
renewable fuel will exceed the RFS requirements.
    In determining their annual gasoline production volume, obligated 
parties must include all of the finished gasoline which they produced 
or imported for use in the contiguous 48 states, and must also include 
reformulated blendstock for oxygenate blending (RBOB), and conventional 
blendstock for oxygenate blending (CBOB). For refiners and importers 
this includes unfinished gasoline produced or imported that will become 
gasoline upon addition of an oxygenate downstream of the refiner. Other 
producers of gasoline, such as blenders,

[[Page 23909]]

will count as their gasoline production only the volumes of blendstocks 
which become gasoline upon their addition to finished gasoline, 
unfinished gasoline, or other blendstocks. Renewable fuels blended into 
gasoline by any party will not be counted as gasoline for the purposes 
of calculating the annual gasoline production volume.
    Small refiners and small refineries are exempt from meeting the 
renewable fuel requirements through 2010. All gasoline producers 
located in Alaska, Hawaii, and noncontiguous U.S. territories and 
parties who import gasoline into these areas will be exempt 
indefinitely. However, if Alaska, Hawaii or a noncontiguous territory 
opts into the RFS program, all of the refiners (except for exempt small 
refiners and refineries), importers, and blenders located in the state 
or territory will be subject to the renewable fuel standard.
    Section III.A provides more details on the standard that must be 
met, while Section III.C describes the parties that are obligated to 
meet the standard.
3. What Qualifies as a Renewable Fuel?
    We have designed the program to cover the range of renewable fuels 
produced today as well as any that might be produced in the future, so 
long as they meet the Act's definition of renewable fuel and have been 
registered and approved for use in motor vehicles. In this manner, we 
believe that the program provides the greatest possible encouragement 
for the development, production, and use of renewable fuels to reduce 
our dependence on petroleum as well as to reduce the carbon dioxide 
emissions that contribute to climate change. In general, renewable 
fuels must be produced from plant or animal products or wastes, as 
opposed to fossil fuel sources. Valid renewable fuels include ethanol 
made from starch seeds, sugar, or cellulosic materials, biodiesel 
(mono-alkyl esters), non-ester renewable diesel, and a variety of other 
products. Both renewable fuels blended into conventional gasoline or 
diesel and those used in their neat (unblended) form as motor vehicle 
fuel will qualify. Section III.B provides more details on the renewable 
fuels that will be allowed to be used for compliance with the standard 
under our program.
4. Equivalence Values of Different Renewables Fuels
    One question that we faced in developing the program was what value 
to place on different renewable fuels and on what basis should that 
value be determined. The Act specifies that each gallon of cellulosic 
biomass ethanol and waste-derived ethanol be treated as if it were 2.5 
gallons of renewable fuel for compliance purposes, but does not specify 
the values for other renewable fuels. Although in the NPRM we 
considered a range of options including straight volume, energy 
content, and requested comment on the merit and basis for setting 
``Equivalence Values'' on several metrics including lifecycle energy or 
greenhouse gas emissions, for this final rule we are requiring that the 
``Equivalence Values'' for the different renewable fuels be based on 
their energy content in comparison to the energy content of ethanol, 
and adjusted as necessary for their renewable content. The result is an 
Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for 
biodiesel (mono alkyl ester) of 1.5, for non-ester renewable diesel of 
1.7, and for cellulosic ethanol and waste-derived ethanol of 2.5. The 
proposed methodology can be used to determine the appropriate 
Equivalence Value for any other potential renewable fuel as well. 
Section III.B.4 provides details of the determination of Equivalence 
Values.
5. How Will Compliance Be Determined?
    Under our program, every gallon of renewable fuel produced or 
imported into the U.S. must be assigned a unique RIN. A block of RINs 
would be assigned to any batch of renewable fuel that is valid for 
compliance purposes under the RFS program. These RINs must be 
transferred with renewable fuel as ownership of a volume of renewable 
fuel is initially transferred through the distribution system. Once the 
renewable fuel is obtained by an obligated party or actually blended 
into a motor vehicle fuel, the RIN can be separated from the batch of 
renewable fuel and then either used for compliance purposes, held, or 
traded.
    RINs represent proof of production which is then taken as proof of 
consumption as well, since all but a trivial quantity of renewable fuel 
produced or imported will be either consumed as fuel or exported. For 
instance, ethanol produced for use as motor vehicle fuel is denatured 
specifically so that it can only be used as fuel. Similarly, biodiesel 
is produced only for use as fuel and has no other significant uses. An 
obligated party demonstrates compliance with the renewable fuel 
standard by accumulating sufficient RINs to cover their individual 
renewable volume obligation. It will not matter whether the obligated 
party used the renewable fuel themselves. An obligated party's 
obligation will be to ensure that a certain amount of renewable fuel 
was used, either by themselves or by someone else, and the RIN is 
evidence that this occurred for a certain volume of renewable fuel. 
Exporters of renewable fuel will also be required to acquire RINs in 
sufficient quantities to cover the volume of renewable fuel exported. 
RINs claimed for compliance purposes by obligated parties will thus 
represent renewable fuel actually consumed as motor vehicle fuel in the 
U.S.
    RINs are valid for compliance purposes for the calendar year in 
which they are generated, or the following calendar year. This approach 
to RIN life is consistent with the Act's prescription that credits be 
valid for compliance purposes for 12 months as of the date of 
generation, where credits are generated at the end of a year when 
compliance is determined. An obligated party can either use RINs to 
demonstrate compliance, or can transfer RINs to any other party. If an 
obligated party is not able to accumulate sufficient RINs for 
compliance in a given year, it can carry a deficit over to the next 
year so long as the full deficit and obligation is covered in the next 
year.
    In order to ensure that previous year RINs are not used 
preferentially for compliance purposes in a manner that would 
effectively circumvent the limitation that RINs be valid for only 12 
months after the year generated, we are setting a cap on the use of 
RINs generated the previous year when demonstrating compliance with the 
renewable volume obligation for the current year. The cap will mean 
that no more than 20 percent of a current year obligation can be 
satisfied using RINs from the previous year. In this manner there is no 
ability for excess renewable fuel use in successive years to cause an 
accumulation of RINs to significantly depress renewable fuel demand in 
any future year. In keeping with the Act, excess RINs not used in the 
year they are generated or in the subsequent year will expire.
    Section III.D provides more details on how obligated parties must 
use RINs for compliance purposes.
6. How Will the Trading Program Work?
    Renewable fuel producers and importers will be required to generate 
RINs when they produce or import a batch of renewable fuel (unless, for 
importers, the RINs have been assigned by a foreign producer registered 
with EPA). They will then be required to transfer those RINs along with 
the renewable fuel batches that they represent whenever they transfer 
ownership of the batch to another party. Likewise any other non-
obligated party

[[Page 23910]]

that takes ownership of a volume of renewable fuel with RINs will be 
required to transfer those RINs with a volume of renewable fuel. The 
RIN can be separated from renewable fuel only by obligated parties (at 
the point when they take ownership of the batch) or a party that 
converts the renewable fuel into motor vehicle fuel (such as upon 
blending with gasoline or diesel).
    Once a RIN is separated from a volume of renewable fuel, it can be 
used for compliance purposes, banked, or traded to another party. 
Separated RINs can be transferred to any party any number of times. 
Recordkeeping and reporting requirements will apply to any party that 
takes ownership of RINs, whether through the ownership of a batch of 
renewable fuel or through the transfer of separated RINs.
    Thus obligated parties can acquire RINs directly through the 
purchase of renewable fuel with assigned RINs or through the open 
market for RINs that is allowed under this proposal. Section III.E 
provides more details on how our RIN trading program will work.
7. How Will the Program Be Enforced?
    As in all EPA fuel regulations, there is a system of registration, 
recordkeeping, and reporting requirements for obligated parties, 
renewable producers and importers (RIN generators), and any parties 
that procure or trade RINs either as part of their renewable purchases 
or separately. In most cases, the recordkeeping requirements are not 
significantly different from what these parties might be doing already 
as a part of normal business practices. The lynch pin to the compliance 
program, however, is the unique RIN number itself coupled with an 
electronic reporting system where RIN generation, RIN use, and RIN 
transactions will be reported and verified. Thus, EPA, as well as 
industry can have confidence that invalid RINs are not generated and 
that there is no double counting.

C. Voluntary Green Labeling Program

    In the proposal EPA asked for comments on the idea of creating a 
voluntary labeling program to encourage the adoption and use of 
practices that minimize the environmental concerns associated with 
renewable fuel production. The proposal suggested adding a ``G'' (for 
green) to the end of the RIN of a fuel to indicate that a gallon of 
renewable fuel was produced with the combination of best farming 
practices and environmentally friendly production methods and 
facilities. EPA received a number of comments on this idea.
    The majority of respondents were very supportive of voluntary 
labeling and encouraged EPA to establish this program through this 
final rulemaking. Two commenters opposed the labeling concept, telling 
EPA that the number and complexity of issues associated with fuel 
production, and particularly with farming practices, would make such a 
program impractical and difficult to implement. EPA also was told that 
it would be hard to audit such a program. Most commenters agreed that 
using the RIN to host the label makes sense, however the use of ``G'' 
for green fuel is insufficient to capture the full range of 
environmental impacts of renewable fuel production and that it would be 
difficult for EPA to establish an appropriate cut-off point for 
determining which fuel qualified for a ``G'' designation. Several 
respondents suggested that EPA instead use a more continuous scale 
based on energy or lifecycle greenhouse gas emissions.
    A well designed voluntary labeling program could permit producers 
and blenders to distinguish their fuels in the marketplace and allow 
consumers to express preferences for ``green'' products through their 
fuel purchases. While such a program could be valuable to producers, 
blenders, and consumers, given the range of comments received on the 
topic, we believe it is important first to continue the dialogue with 
the various stakeholders to ensure that the program adequately 
addresses the issues raised prior to putting any such program in place. 
Thus we are not finalizing a voluntary labeling program. We will 
continue to investigate the issues surrounding a voluntary labeling 
program and the various ways in which it could be designed. In 
particular we are interested in further exploring methods to 
incorporate lifecycle impacts into a voluntary labeling program and 
consumer expectations for such ``green'' labeling.

III. Complying With the Renewable Fuel Standard

    According to the Energy Act, the RFS program places obligations on 
individual parties such that the renewable fuel volumes shown in Table 
I.B-1 are used as motor vehicle fuel in the U.S. each year. To 
accomplish this, the Agency must calculate and publish a standard by 
November 30 of each year which is applicable to every obligated party. 
On the basis of this standard each obligated party determines the 
volume of renewable fuel that it must ensure is consumed as motor 
vehicle fuel. In addition to setting the standard, we must clarify who 
the obligated parties are and what volumes of gasoline are subject to 
the standard. Obligated parties must also know which renewable fuels 
are valid for RFS compliance purposes, and the relative values of each 
type of renewable fuel in terms of compliance. This section discusses 
how the annual standard is determined and which parties and volumes of 
gasoline will be subject to the requirements.
    Because renewable fuels are not produced or distributed evenly 
around the country, some obligated parties will have easier access to 
renewable fuels than others. As a result, the RFS program depends on a 
robust trading program. This section also describes all the elements of 
our trading program.

A. What Is the Standard That Must Be Met?

1. How Is the Percentage Standard Calculated?
    Table I.B-1 shows the required total volume of renewable fuel 
specified in the Act for 2007 through 2012. The renewable fuel standard 
is based primarily on (1) the 48-state gasoline consumption volumes 
projected by EIA (as the Act exempts Hawaii and Alaska, subject to 
their right to opt-in, as discussed in Section III.C.4), and (2) the 
volume of renewable fuels required by the Act for the coming year. The 
renewable fuel standard will be expressed as a volume percentage of 
gasoline sold or introduced into commerce in the U.S., and will be used 
by each refiner, blender or importer to determine their renewable 
volume obligation. The applicable percentage is set so that if each 
regulated party meets the percentage and total gasoline consumption 
does not fall short of EIA projections then the total amount of 
renewable fuel used will meet the total renewable fuel volume specified 
in Table I.B-1.
    In determining the applicable percentage for a calendar year, the 
Act requires EPA to adjust the standard to prevent the imposition of 
redundant obligations on any person and to account for the use of 
renewable fuel during the previous calendar year by exempt small 
refineries, defined as refineries that process less than 75,000 bpd of 
crude oil. As a result, in order to be assured that the percentage 
standard will in fact result in the volumes shown in Table I.B-1, we 
must make several adjustments to what is otherwise a simple 
calculation.
    As stated, the renewable fuel standard for a given year is 
basically the ratio of the amount of renewable fuel specified in the 
Act for that year to the projected 48-state non-renewable gasoline 
volume

[[Page 23911]]

for that year. While the required amount of total renewable fuel for a 
given year is provided by the Act, the Act requires EPA to use an EIA 
estimate of the amount of gasoline that will be sold or introduced into 
commerce for that year. The level of the percentage standard is reduced 
if Alaska, Hawaii, or a U.S. territory choose to participate in the RFS 
program, as gasoline produced in or imported into those states or 
territories would then be subject to the standard. Should any of these 
states or territories opt into the RFS program, the projected gasoline 
volume would increase above that consumed in the 48 contiguous states.
    In the proposal, we stated that EIA had indicated that the best 
estimation of the coming year's gasoline consumption is found in Table 
5a (U.S. Petroleum Supply and Demand: Base Case) of the October issue 
of the monthly EIA publication Short-Term Energy Outlook which 
publishes quarterly energy projections. Commenters on this issue 
supported the use of the October issue of EIA's Short-Term Energy 
Outlook (STEO), Table 5a, for the purpose of estimating the next year's 
gasoline consumption, and we have used the October 2006 STEO values for 
estimating 2007 gasoline consumption for this final rule.
    The gasoline volumes in the STEO include renewable fuel use. As 
discussed below in Section III.C.1, the renewable fuel obligation does 
not apply to renewable blenders. Thus, the gasoline volume used to 
determine the standard must be the non-renewable portion of the 
gasoline pool, in order to achieve the volumes of renewables specified 
in the Act. In order to get a total non-renewable gasoline volume, we 
must subtract the renewable fuel volume from the total gasoline volume. 
EIA has indicated that the best estimation of the coming year's 
renewable fuel consumption is found in Table 11 (U.S. Renewable Energy 
Use by Sector: Base Case) of the October issue of the STEO. As with the 
gasoline projections discussed above, we have used the October 2006 
STEO values for estimating 2007 renewable fuel values for this final 
rule.
    The Act exempts small refineries \7\ from the RFS requirements 
until the 2011 compliance period. As discussed in Section III.C.3.a, as 
proposed, EPA is also exempting small refiners \8\ from the RFS 
requirements until 2011, and is treating small refiner gasoline volumes 
the same as small refinery gasoline volumes. Since small refineries and 
small refiners are exempt from the program until 2011, EPA is excluding 
their gasoline volumes from the overall non-renewable gasoline volume 
used to determine the applicable percentage. EPA believes this is 
appropriate because the percentage standard should be based only on the 
gasoline subject to the renewable volume obligation. Because small 
refineries and small refiners are exempt (unless they waive exemption) 
only through the 2010 compliance period when the exemption ends, 
calculation of the standard for calendar year 2011 and beyond will 
include small refinery and small refiner volumes.\9\ Using information 
from gasoline batch reports submitted to EPA, EIA data, and input from 
the California Air Resources Board regarding California small refiners, 
we are finalizing a small refiner exemption adjustment to the standard 
of a constant 13.5%,\10\ consistent with the proposal.
---------------------------------------------------------------------------

    \7\ Under the Act, small refineries are those with 75,000 bbl/
day or less average aggregate daily crude oil throughput.
    \8\ Small refiners are those entities who produced gasoline from 
crude oil in 2004, and who meet the crude processing capability (no 
more than 155,000 barrels per calendar day, bpcd) and employee (no 
more than 1500 people) criteria as specified in previous EPA fuel 
regulations.
    \9\ As discussed in section III.C.3.a of this preamble, the 
small refinery exemption may be extended under 211(o)(9)(A)(ii) or 
(B) of the Clean Air Act as amended by the Energy Policy Act.
    \10\ ``Calculation of the Small Refiner/Small Refinery Fraction 
for the Renewable Fuel Program,'' memo to the docket from Christine 
Brunner, ASD, OTAQ, EPA September 2006.
---------------------------------------------------------------------------

    The Act 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 RFS program. Accounting for 
this volume of renewable fuel would reduce the total volume of 
renewable fuel use required of others, and thus directionally would 
reduce the percentage standard. However, as discussed in the proposal, 
there are no such data available, 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 and would not significantly change the resulting percentage 
standard. Because whatever renewables small refiners and small 
refineries blend will be reflected as RINs available in the market, 
there is no need for a separate accounting of their renewable fuel use 
in the equation used to determine the standard. We thus proposed that 
this value be zero, and we are finalizing the equation as such.
    We also proposed not to include renewable fuel used in Alaska, 
Hawaii, or U.S. territories when subtracting renewable fuel volumes 
from the anticipated total gasoline volumes in EIA projections. The Act 
requires that the renewable fuel be consumed in the contiguous 48 
states unless Alaska, Hawaii, or a U.S. territory opt-in. However, 
because renewable fuel produced in Alaska, Hawaii, and U.S. territories 
is unlikely to be transported to the contiguous 48 states, including 
their renewable fuel volumes in the calculation of the standard would 
not serve the purpose intended by the Act of ensuring that the 
statutorily required renewable fuel volumes are consumed in the 48 
contiguous States. We are finalizing the exclusion of these areas' 
renewable fuel use as proposed.
    We stated that any deficit carryover from 2006 would increase the 
2007 standard. Since renewable fuel use in 2006 exceeded the 2.78 
percent default standard, there is no deficit to carry over to 2007. 
Beginning with the 2007 compliance period, when annual individual party 
compliance replaces collective compliance, any deficit is calculated 
for an individual party and is included in the party's Renewable Volume 
Obligation (RVO) determination, as discussed in Section III.A.4.
    In summary, the total projected non-renewable gasoline volumes from 
which the annual standard is calculated is based on EIA projections of 
gasoline consumption in the contiguous 48 states, adjusted by a 
constant percentage of 13.5% to account for small refinery/refiner 
volume, with built-in correction factors to be used when and if non-
contiguous states and territories opt-in to the program. If actual 
gasoline consumption were to exceed the EIA projection, the result 
would be that renewable fuel volumes will exceed the statutory 
requirements. Conversely, if actual gasoline consumption was less than 
the EIA projection for a given year, theoretically a renewable fuel 
shortfall could occur. However, our projections of renewable fuel use 
due to market demand would make a shortfall extremely unlikely 
regardless of the error in gasoline consumption projections.
    The following formula will be used to calculate the percentage 
standard:

[[Page 23912]]

[GRAPHIC] [TIFF OMITTED] TR01MY07.056

Where:

RFStdi = Renewable Fuel standard in year i, in percent.
RFVi = Annual volume of renewable fuels required by 
section 211(o)(2)(B) of the Act for year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48 
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that 
is projected to be consumed in the 48 contiguous states, in year i, 
in gallons.
GSi = Amount of gasoline projected to be used in Alaska, 
Hawaii, or a U.S. territory in year i if the state or territory 
opts-in, in gallons.
RSi = Amount of renewable fuel blended into gasoline that 
is projected to be consumed in Alaska, Hawaii, or a U.S. territory 
in year i if the state or territory opts-in, in gallons.
GEi = Amount of gasoline projected to be produced by 
exempt small refineries and small refiners in year i, in gallons 
(through 2010 only unless exemption extended under Sec. Sec.  
211(o)(9)(A)(ii) or (B)). Equivalent to 0.135*(Gi-
Ri).
Celli = Beginning in 2013, the amount of renewable fuel 
that is required to come from cellulosic sources, in year i, in 
gallons (250,000,000 gallons minimum).

    After 2012 the Act requires that the applicable volume of required 
renewable fuel specified in Table I.B-1 include a minimum of 250 
million gallons that are derived from cellulosic biomass. As shown in 
Table III.A.2-1 below, we have estimated this value (250 million 
gallons) as a percent of an obligated party's production for 2013. 
Thus, an obligated party will be subject to two standards in 2013 and 
beyond, a non-cellulosic standard and a cellulosic standard. We are 
therefore also finalizing the following formula for calculating the 
cellulosic standard that is required beginning in 2013:
[GRAPHIC] [TIFF OMITTED] TR01MY07.057

Where, except for RFCelli, the variable descriptions are 
as discussed above. The definition of RFCelli is:

RFCelli = Renewable Fuel Cellulosic Standard in year i, 
in percent

    Note that after 2012 cellulosic RINs cannot be used to satisfy the 
non-cellulosic RFS standard (RFStdi). The amount of 
renewable fuel that is required to come from cellulosic sources 
(Celli) is a fixed amount.
    We are not finalizing regulations that would specify the criteria 
under which a state could petition the EPA for a waiver of the RFS 
requirements, nor the ramifications of Agency approval of such a waiver 
in terms of the level or applicability of the standard. As discussed in 
the proposal, there was no clear way to include such a provision in the 
context of the program being finalized. As a result, the formula for 
the standard shown above does not include any components to account for 
Agency approval of a state petition for a waiver of the RFS 
requirements. Should EPA grant such a waiver in the future, it will 
determine at that time what adjustments to make to the standard.
2. What Are the Applicable Standards?
    As discussed in the proposal, EPA will set the percentage standard 
for each upcoming year based on the most recent EIA STEO projections, 
and using the other sources of information as noted above. EPA will 
publish the standard in the Federal Register by November 30 of the 
preceding year. The standards are used to determine the renewable 
volume obligation based on an obligated party's total gasoline 
production or import volume in a calendar year, January 1 through 
December 31. The percentage standards do not apply on a per gallon 
basis. An obligated party will calculate its Renewable Volume 
Obligation (discussed in Section III.A.4) using the annual standard.
    In the NPRM, we estimated the standards for 2007 and later using 
data available at the time and the formulas discussed above.\11\ We 
have revised these values based on more recent data, and using EIA's 
October 2006 STEO gasoline and renewable fuel consumption 
projections.\12\ In the proposal, we had used the lower heating value 
of ethanol for converting from Btu to gallons of ethanol for the 
purpose of calculating the standard. However, for this final rule, we 
have used the higher heating value of ethanol as recommended by 
commenters, to be consistent with EIA practices.\13\ \14\ Variables 
related to state or territory opt-ins were set to zero since we do not 
have any information related to their participation at this time. As 
mentioned earlier, we estimate the small refinery and small refiner 
fraction to be 13.5%. The exemption for small refineries and small 
refiners ends at the end of the 2010 compliance period, unless extended 
as discussed in Section III.C.3.a. Based on all of these factors, the 
standard for 2007 is 4.02%. Projected values of the standard for 2008 
and beyond are shown in Table III.A.2-1.
---------------------------------------------------------------------------

    \11\ ``Calculation of the Renewable Fuel Standard'' memo to the 
docket from Christine Brunner, ASD, OTAQ, EPA, September 2006.
    \12\ ``Calculation of the Renewable Fuel Standard--Revised'' 
memo to the docket from Christine Brunner, ASD, OTAQ, EPA, April 
2007.
    \13\ The higher (or gross or upper) heating value is used in all 
Btu calculations for EIA's Annual Energy Review and in related EIA 
publications (see discussion in EIA's Annual Energy Review, Appendix 
A, Thermal Conversion Factors).
    \14\ The lower heating value (LHV) is used to represent energy 
content in the context of setting Equivalence Values as described in 
Section III.B.4 because it more accurately reflects the energy 
available in the fuel to produce work.

                  Table III.A.2-1.--Projected Standards
------------------------------------------------------------------------
                                                          Cellulosic
              Year                Projected standard       standard
------------------------------------------------------------------------
2008............................  4.63%.............  Not applicable.
2009............................  5.21%.............  Not applicable.
2010............................  5.80%.............  Not applicable.
2011............................  5.38%.............  Not applicable.
2012............................  5.42%.............  Not applicable.
2013+...........................  5.24% min. (non-    0.18% min.
                                   cellulosic).
------------------------------------------------------------------------


[[Page 23913]]

    As discussed in Section II.A.5, for calendar year 2013 and 
thereafter, the applicable volumes will be determined in accordance 
with separate statutory provisions that include EPA coordination with 
the Departments of Agriculture and Energy, and a review of the program 
during calendar years 2006 through 2012. The Act specifies that this 
review consider the impact of the use of renewable fuels on the 
environment, air quality, energy security, job creation, and rural 
economic development, and the expected annual rate of future production 
of renewable fuels, including cellulosic ethanol. We intend to conduct 
another rulemaking as we approach the 2013 timeframe that would include 
our review of these factors. That rulemaking will present our 
conclusions regarding the appropriate applicable volume of renewable 
fuel for use in calculating the renewable fuel standard for 2013 and 
beyond. The program finalized by today's rule will continue to apply 
after 2012, though some elements may be modified in the rulemaking 
setting the standards for 2013 and beyond. Today's rule does not 
contain a mechanism for establishing a post-2012 standard.
3. Compliance in 2007
    The Energy Act requires that EPA promulgate regulations to 
implement the RFS program, and if EPA did not issue such regulations 
then a default standard for renewable fuel use would apply in 2006. On 
December 30, 2005 we promulgated a direct final rule to interpret and 
implement the application of the statutory default standard of 2.78 
percent in calendar year 2006 (70 FR 77325). However, the Act provides 
no default standard for any other year.
    In the NPRM we stated our expectation that, due to the limited time 
available for this rulemaking, we would be unable to publish the final 
rule and have it become effective by January 1, 2007. We discussed 
several ways that we could specify how, and for what time periods, the 
applicable standard and other program requirements would apply to 
regulated parties for gasoline produced during 2007. We discussed a 
collective compliance approach similar to that applied in 2006, as well 
as a ``full year'' approach that would have based the renewable volume 
obligation for each obligated party on all gasoline produced starting 
on January 1, 2007 regardless of the effective date of the rule. 
However, due to a number of issues with these approaches, we proposed a 
``prospective'' approach in which the renewable fuel standard would be 
applied to only those volumes of gasoline produced after the effective 
date of the final rule. Essentially the renewable volume obligation for 
2007 would be based on only those volumes of gasoline produced or 
imported by an obligated party prospectively from the effective date of 
the rulemaking forward, and renewable producers would not have to begin 
generating RINs and maintaining the necessary records until this same 
date.
    We received no comments supporting the alternative ``full year'' 
approach to 2007 compliance. However, several parties expressed a 
preference for either a collective compliance approach for 2007, or if 
not that then delaying implementation of the comprehensive program to 
January 1, 2008. They argued that regulated parties needed additional 
time to put into place the sophisticated RIN tracking systems that 
would be required. The additional time would also allow regulated 
parties to debug the systems, train personnel, and put support programs 
into place. The American Coalition for Ethanol also argued that the 
prospective approach did not guarantee that the total renewable fuel 
volumes required by the Act for 2007 would actually be used in 2007, 
whereas a collective compliance approach would. Parties in favor of a 
collective compliance approach argued that EPA has the authority to 
implement such an approach despite the fact that the Act does not 
explicitly give EPA this authority, and also argued that there was no 
need to include any form of credit carryover under a collective 
compliance approach.
    However, a number of refiners and their associations opposed a 
collective compliance approach to 2007 and expressed strong support for 
the proposed prospective approach. They argued that a start date at 
least 60 days from the date of publication of the final rule would 
provide sufficient time to obligated parties for making the necessary 
adjustments for compliance. They also argued that they should be 
afforded the opportunity to participate as soon as possible in the 
trading program, which the collective compliance approach used for 2006 
would preclude for 2007.
    We continue to believe that a collective compliance approach is not 
appropriate for 2007. The Energy Act requires us to promulgate 
regulations that provide for the generation of credits by any person 
who over complies with their obligation. It also stipulates that a 
person who generates credits must be permitted to use them for 
compliance purposes, or to transfer them to another party. These credit 
provisions have meaning only in the context of an individual obligation 
to meet the applicable standard. Delaying a credit program until 2008 
would mean the credit provisions have no meaning at all for 2007, since 
under a collective compliance approach no individual facility or 
company would be liable for meeting the applicable standard. Including 
a ``collective'' credit or deficit carryforward as part of a collective 
compliance program would also not fully implement the credit provisions 
of the Act. The prospective compliance approach, in contrast, not only 
provides obligated parties with the opportunity to generate credits, 
but also provides the industry with the certainty they need to comply 
and is relatively straightforward to implement.
    Rather than requiring the program to begin on the effective date of 
the rule as proposed (60 days following publication in the Federal 
Register), we are finalizing a start date of September 1, 2007. From 
this date forward, the renewable fuel standard will be applicable to 
all gasoline produced or imported, and all renewable fuels produced or 
imported will have to be assigned a RIN. All regulated parties must be 
registered by this date, and the recordkeeping responsibilities will 
also begin. By setting such a date, industry will be able to plan with 
confidence to start complying upon signature of the rule, rather than 
having the start date depend upon the timing of publication of this 
final rule in the Federal Register. We recognize the concerns expressed 
in comments that time is needed to prepare Information Technology (IT) 
systems to comply with the program. However, we believe that a 
September 1, 2007 start date will provide sufficient time. The final 
rule is in most respects consistent with the NPRM, and based on 
discussions with industry, plans for implementation are already 
underway. Furthermore, a September 1, 2007 start date will likely 
provide regulated parties some additional time to prepare in comparison 
to simply setting the start date as 60 days following publication of 
the rule.
    As stated in the NPRM, we recognize that the prospective approach 
to 2007 compliance will not guarantee by regulation that the total 
renewable fuel volumes required by the Act for 2007 would actually be 
used in 2007. However, current projections from the Energy Information 
Administration (EIA) on the volume of renewable fuel expected to be 
produced in 2007 indicate that the Act's required volumes will be 
exceeded by a substantial margin due to the relative economic value of 
renewable fuels in comparison to gasoline. We are confident that the 
combined effect of the regulatory

[[Page 23914]]

requirements for 2007 and the expected market demand for renewable 
fuels will lead to greater renewable fuel use in 2007 than is called 
for under the Act. Current renewable production already exceeds the 
rate required for all of 2007, and as discussed in Section VI, capacity 
is expected to continue to grow. Furthermore, refiners and importers 
are not required to meet any requirements under the Act until EPA 
adopts the regulations, and EPA is authorized to consider appropriate 
lead time in establishing the regulatory requirements.\15\ Under this 
option we believe there will be reasonable lead-time for regulated 
parties to meet their 2007 compliance obligations. While no option 
before us is perhaps totally consistent with all of the provisions of 
the Act, we believe the rule as adopted does the best job possible 
given the circumstances of implementing all of the provisions of the 
Act for 2007.
---------------------------------------------------------------------------

    \15\ The statutory default standard for 2006 is the one 
exception to this, since it directly establishes a renewable fuel 
obligation applicable to refiners and importers in the event that 
EPA does not promulgate regulations.
---------------------------------------------------------------------------

4. Renewable Volume Obligations
    In order for an obligated party to demonstrate compliance, the 
percentage standards described in Section III.A.2 which are applicable 
to all obligated parties must be converted into the volume of renewable 
fuel each obligated party is required to satisfy. This volume of 
renewable fuel is the volume for which the obligated party is 
responsible under the RFS program, and is referred to here as its 
Renewable Volume Obligation (RVO).
    The calculation of the RVO requires that the standard shown in 
Table III.A.2-1 for a particular compliance year be multiplied by the 
gasoline volume produced by an obligated party in that year. To the 
degree that an obligated party did not demonstrate full compliance with 
its RVO for the previous year, the shortfall is included as a deficit 
carryover in the calculation. The equation used to calculate the RVO 
for a particular year is shown below:

RVOi = Stdi x GVi + Di-1

Where:

RVOi = The Renewable Volume Obligation for the obligated 
party for year i, in gallons.
Stdi = The RFS program standard for year i, in percent.
GVi = The non-renewable gasoline volume produced by an 
obligated party in year i, in gallons.

Di-1 = Renewable fuel deficit carryover from the previous 
year, in gallons.

    The Energy Act only permits a deficit carryover from one year to 
the next if the obligated party achieves full compliance with its RVO 
including the deficit carryover in the second year. Thus deficit 
carryovers could not occur two years in succession. They could, 
however, occur as frequently as every other year for a given obligated 
party.
    The calculation of an obligated party's RVO is necessarily 
retrospective, since the total gasoline volume that it produces in a 
calendar year will not be known until the year has ended. However, the 
obligated party will have an incentive to project gasoline volumes, and 
thus the RVO, throughout the year so that it can spread its efforts to 
comply across the entire year. Most refiners and importers will be able 
to project their annual gasoline production volumes with a minimum of 
uncertainty based on their historical operations, capacity, plans for 
facility downtimes, knowledge of gasoline markets, etc. Even if 
unforeseen circumstances (e.g., hurricane, unit failure, etc.) 
significantly reduced the production volumes in comparison to their 
projections, their RVO will likewise be reduced proportionally and 
their ability to comply with the RFS requirements will be only 
minimally affected. Each obligated party's projected RVO for a given 
year becomes more accurate as that year progresses, but the obligated 
party should nevertheless have a sufficiently accurate estimate of its 
RVO at the beginning of the year to allow it to begin its efforts to 
comply.

B. What Counts as a Renewable Fuel in the RFS Program?

    Section 211(o) of the Clean Air Act defines ``renewable fuel'' and 
specifies many of the details of the renewable fuel program. The 
following section provides EPA's views and interpretations on issues 
related to what fuels may be counted towards compliance with the RVO, 
and how they are counted.
1. What Is a Renewable Fuel That Can Be Used for Compliance?
    The statutory definition of renewable fuel includes cellulosic 
ethanol and waste derived ethanol. It includes biodiesel, as defined in 
the Energy Act.\16\ It also includes all motor vehicle fuels that are 
produced from biomass material such as grain, starch, oilseeds, animal, 
or fish materials including fats, greases and oils, sugarcane, sugar 
beets, tobacco, potatoes or other biomass (such as bagasse from sugar 
cane, corn stover, and algae and seaweed). In addition, it includes 
motor vehicle fuels made using a feedstock of natural gas if produced 
from a biogas source such as a landfill, sewage waste treatment plant, 
feedlot, or other place where decaying organic material is found.
---------------------------------------------------------------------------

    \16\ As discussed below, for purposes of this rulemaking, the 
regulations separate ``biodiesel'' as defined in the Energy Act, 
into biodiesel (diesels that meet the Energy Act's definition and 
are a mono-alkyl ester) and renewable diesel (other diesels that 
meet the Energy Act's definition but are not mono-alkyl esters).
---------------------------------------------------------------------------

    According to the Act, the motor vehicle fuels must be used ``to 
replace or reduce the quantity of fossil fuel present in a fuel mixture 
used to operate a motor vehicle.'' Some motor vehicle fuels can be used 
in both motor vehicles or nonroad engines or equipment. For example, 
highway gasoline and diesel fuel are often used in both highway and 
off-highway applications. Compressed natural gas can likewise be used 
in either highway or nonroad applications. For purposes of the 
renewable fuel program, EPA considers a fuel to be a ``motor vehicle 
fuel'' and to be ``a fuel mixture used to operate a motor vehicle,'' 
based on its potential for use in highway and nonroad vehicles, without 
regard to whether it, in fact, is used in a highway vehicle 
application. EPA does not believe that the much more complex and costly 
regulatory scheme that would be needed to track motor vehicle fuel use 
versus off-road fuel use would be justified. (As discussed further 
below, heaters and boilers are not considered highway or nonroad engine 
applications and renewable fuel produced or imported specifically for 
use in such equipment is not valid for compliance purposes under the 
RFS program.) If it is a fuel that could be used in highway vehicles, 
it will satisfy these parts of the definition of renewable fuel, 
whether it is later used in highway or nonroad applications. This will 
allow a motor vehicle fuel that otherwise meets the definition to be 
counted towards a party's RVO without the need to track it to determine 
its actual application in a highway vehicle, and provided only that the 
producer does not know that the fuel will be used for a purpose other 
than highway and nonroad engine applications. This is also consistent 
with the requirement that EPA base the renewable fuel obligation on 
estimates of the entire volume of gasoline consumed, without regard to 
whether it is used in highway or nonroad applications.
    Renewable fuel as defined, may be made from a number of different 
types of feedstocks. For example, the Fisher-Tropsch process can use 
methane gas from landfills as a feedstock, to produce diesel or 
gasoline. Vegetable oil made

[[Page 23915]]

from oilseeds such as rapeseed or soybeans can be used to make 
biodiesel or renewable diesel. Methane, made from landfill gas (biogas) 
can be used to make methanol, or can be used directly as a fuel in 
vehicles with engines designed to run on compressed natural gas. Also, 
some vegetable oils or animal fats can be processed in distillation 
columns in refineries to make gasoline; as such, the renewable 
feedstock serves as a ``renewable crude,'' and the resulting gasoline 
or diesel product would be a renewable fuel. This last example is 
discussed in further detail in Section III.B.3 below.
    As this discussion shows, the definition of renewable fuel in the 
Act is broad in scope, and covers a wide range of fuels. While ethanol 
is used primarily in combination with gasoline, the definition of 
renewable fuel in the Act is not limited to fuels that can be blended 
with gasoline. Various fuels that meet the definition of renewable fuel 
can be used in their neat form, such as ethanol, biodiesel, methanol or 
natural gas. Others, including ethanol may be used to produce a 
gasoline blending component (such as ETBE). At the same time, the RFS 
regulatory program is to ``ensure that gasoline sold or introduced into 
commerce * * * contains the applicable volume of renewable fuel.'' This 
applicable volume is specified as a total volume of renewable fuel on 
an aggregate basis. Congress also clearly specified that one renewable 
fuel, biodiesel, could be counted towards compliance even though it is 
not a gasoline component, and does not directly displace or replace 
gasoline. The Act is unclear on whether other fuels that meet the 
definition of renewable fuel, but are not used in gasoline, could also 
be used to demonstrate compliance towards the aggregate national use of 
renewable fuels.
    EPA interprets the Act as allowing regulated parties to demonstrate 
compliance based on any fuel that meets the statutory definition for 
renewable fuel, whether it is directly blended with gasoline or not. 
This would include neat alternative fuels such as ethanol, methanol, 
and natural gas that meet the definition of renewable fuel. This is 
appropriate for several reasons. First, it promotes the use of all 
renewable fuels, which will further the achievement of the purposes 
behind this provision. Congress did not intend to limit the program to 
only gasoline components, as evidenced by the provision for biodiesel, 
and the broad definition of renewable fuel evidences an intention to 
address more renewable fuels than those used with gasoline. Second, in 
practice EPA expects that the overwhelming volume of renewable fuel 
used to demonstrate compliance with the renewable fuel obligation would 
still be ethanol blended with gasoline. Finally, as discussed later, 
EPA's compliance program is based on assigning volumes at the point of 
production, and not at the point of blending into motor vehicle fuel. 
This interpretation avoids the need to track renewable fuels downstream 
to ensure they are blended with gasoline and not used in their neat 
form; the gasoline that is used in motor vehicles is reduced by the 
presence of renewable fuels in the gasoline pool whether they are 
blended with gasoline or not. Comments received on this interpretation 
were favorable towards it. EPA continues to believe, therefore, that 
this approach is consistent with the intent of Congress and is a 
reasonable interpretation of the Act. One commenter indicated that a 
logical extension of this reasoning would provide that renewable fuel 
that could be used in motor vehicles is still a renewable fuel under 
the Act when used by renewable fuel producers in a boiler or heater. 
EPA disagrees. The term ``renewable fuel'' means ``motor vehicle fuel 
that * * * is used to replace or reduce the quantity of fossil fuel 
present in a fuel mixture used to operate a motor vehicle.'' We believe 
that all but a trivial quantity of renewable fuels that can be used in 
motor vehicles will ultimately be used as motor vehicle fuel. Producers 
of ethanol biodiesel and other products that can be used as motor 
vehicle fuel can generally assume, therefore, that their products will 
be used in that way, and can assign RINs to their product without 
tracking its ultimate use. However, renewable fuel used onsite in a 
boiler or heater by a renewable fuel producer clearly is not a motor 
vehicle fuel used to replace or reduce the quantity of fossil fuel 
present in a fuel mixture used to operate a motor vehicle.
    Under the Act, renewable fuel includes ``cellulosic biomass 
ethanol'' and ``waste derived ethanol'', each of which is defined 
separately. Ethanol can be cellulosic biomass ethanol in one of two 
ways, as described below.
a. Ethanol Made From a Cellulosic Feedstock
    The simplest process of producing ethanol is by fermenting sugar in 
sugar cane or beets, but ethanol can also be produced from starch in 
corn and other feedstocks by first converting the starch to sugar. 
Ethanol can also be produced from complex carbohydrates, such as the 
cellulosic portion of plants or plant products. The cellulose is first 
converted to sugars (by hydrolysis); then the same fermentation process 
is used as for sugar to make ethanol. Cellulosic feedstocks (composed 
of cellulose and hemicellulose) are currently more difficult and costly 
to convert to sugar than are starches. While the cost and difficulty 
are a disadvantage, the cellulosic process offers the advantage that a 
wider variety of feedstocks can be used. Ultimately with more 
feedstocks available from which to make ethanol more volume of ethanol 
can be produced.
    The Act provides the definition of cellulosic biomass ethanol, 
which states:

    ``The term `cellulosic biomass ethanol' means ethanol derived 
from any lignocellulosic or hemicellulosic matter that is available 
on a renewable or recurring basis, including:
    (i) Dedicated energy crops and trees;
    (ii) Wood and wood residues;
    (iii) Plants;
    (iv) Grasses;
    (v) Agricultural residues;
    (vi) Animal wastes and other waste materials, and
    (viii) Municipal solid waste.''

    Examples of cellulosic biomass source material include rice straw, 
switch grass, and wood chips. Ethanol made from these materials would 
qualify under the definition as cellulosic ethanol. In addition to the 
above sources of feedstocks for cellulosic biomass ethanol, the Act's 
definition also includes animal waste, municipal solid wastes, and 
other waste materials. ``Other waste materials'' generally includes 
waste material such as sewage sludge, waste candy, and waste starches 
from food production, but for purposes of the definition of cellulosic 
ethanol discussed in III.B.1.b below, it can also mean waste heat 
obtained from an off-site combustion process.
    Although the definitions of ``cellulosic biomass ethanol'' and 
``waste derived ethanol'' both include animal wastes and municipal 
solid waste in their respective lists of covered feedstocks, there 
remains a distinction between these types of ethanol. If the animal 
wastes or municipal solid wastes contain cellulose or hemicellulose, 
the resulting ethanol can be termed ``cellulosic biomass ethanol.'' If 
the animal wastes or municipal solid wastes do not contain cellulose or 
hemicellulose, then the resulting ethanol is labeled ``waste derived 
ethanol.'' This is discussed further in Section III.B.1.c below.

[[Page 23916]]

b. Ethanol Made From Any Feedstock in Facilities Using Waste Material 
To Displace 90 Percent of Normal Fossil Fuel Use
    The definition of cellulosic biomass ethanol in the Act also 
provides 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 percent or more of the fossil fuel 
normally used in the production of ethanol.'' The statutory language 
suggests that there are two methods through which ``animal and other 
waste materials'' may be considered for displacing fossil fuel. The 
first method is the digestion of animal wastes or other waste 
materials. EPA has interpreted the term ``digestion'' to mean the 
conversion of animal or other wastes into methane, which can then be 
combusted as fuel. We base our interpretation on the practice in 
industry of using anaerobic digesters to break down waste products such 
as manure into methane. Anaerobic digestion refers to the breakdown of 
organic matter by bacteria in the absence of oxygen, and is used to 
treat waste to produce renewable fuels. We note also that the digestion 
of animal wastes or other waste materials to produce the fuel used at 
the ethanol plant does not have to occur at the plant itself. Methane 
made from animal or other wastes offsite and then purchased and used at 
the ethanol plant would also qualify.
    The second method is suggested by the term ``otherwise used'' which 
we interpret to mean (1) the direct combustion of the waste materials 
as fuel at an ethanol plant, or (2) the use of thermal energy that 
itself is a waste product; e.g., waste heat that is obtained from an 
off-site combustion process such as a neighboring plant that has a 
furnace or boiler from which the waste heat is captured. With respect 
to the first meaning, ``other waste materials'' includes but is not 
limited to waste materials from tree farms (tops, branches, limbs, 
etc.), or waste materials from saw mills (sawdust, shavings and bark) 
as well as other vegetative waste materials such as corn stover, or 
sugar cane bagasse, that could be used as fuel for gasifier/boiler 
units at ethanol plants. Since these materials are not also used as a 
feedstock to starch-based ethanol plants, they are truly waste 
materials. Although these waste materials conceivably could be 
feedstocks to a cellulosic ethanol plant, their use in that manner is 
sufficiently challenging at the current time that EPA believes that 
such use does not subvert the intent of the definition.\17\ Since corn 
kernels can readily be used as a feedstock in a typical ethanol 
production facility, their use as a fuel for gasified/boiler units at a 
corn ethanol plant would not be considered use of ``other waste 
material'' for purposes of the definition of cellulosic biomass 
ethanol.
---------------------------------------------------------------------------

    \17\ On the other hand, wood from plants or trees that are grown 
as an energy crop may not qualify as a waste-derived fuel in an 
ethanol facility because such wood would not qualify as waste 
materials under this portion of the definition. Under the definition 
of renewable fuels and cellulosic biomass ethanol, however, such 
wood material could serve as a feedstock in a cellulosic ethanol 
plant, since these definitions do not restrict such feedstock to 
waste materials only.
---------------------------------------------------------------------------

    Regarding the use of waste heat as a source of thermal energy, we 
note that there may be situations in which an off-site furnace, boiler 
or heater creates excess or waste heat that is not used in the process 
for which the thermal energy is employed. For example, a glass furnace 
generates a significant amount of waste heat that often goes unused. We 
have therefore included in the regulatory definition of cellulosic 
biomass ethanol waste heat generated from off-site sources in the 
definition of ``other waste materials'' that can be used to displace 
90% of the fossil fuel otherwise used at an ethanol production 
facility.
    Several commenters argued that because the source of the waste heat 
is ultimately a fossil fuel in most cases that it should not be 
considered an ``other waste material''. The Agency recognizes that 
fossil fuel is ultimately the source of most waste heat, but it is also 
the case that waste heat that is uncaptured represents a loss of energy 
that could otherwise displace fossil fuel use elsewhere. Specifically, 
waste heat used at an ethanol plant would result in displacement of 
fossil fuel use at the plant. In writing the proposed rule, we were 
aware of the concern raised by the commenters and therefore proposed to 
restrict waste heat to off-site sources only. We believe that this 
approach minimizes the concern. We disagree with another commenter that 
such restriction would create a perverse incentive for facilities near 
ethanol plants to oversize its combustion units to sell waste heat to 
the neighboring ethanol facilities where it would be used to displace 
fossil fuel. It is highly unlikely that businesses would incur the 
additional expense of building an oversized combustion unit for the 
sale of waste heat. Also, the 2.5 gallon value given for one gallon of 
cellulosic ethanol as provided by the Act extends only through 2012. 
Any additional market value for waste heat used to qualify ethanol as 
cellulosic would therefore be of relatively short duration and not 
likely to warrant investment in oversized combustion units.\18\
---------------------------------------------------------------------------

    \18\ The term ``other waste materials'' is also included in the 
portions of the definitions of ``cellulosic biomass ethanol'' and 
``waste-derived ethanol'' that identify feedstocks. The inclusion of 
off-site generated waste heat in the definition of ``other waste 
materials'', however, applies only to the portion of the definition 
of cellulosic biomass ethanol that relates to displacement of fossil 
fuels, and does not apply to the term ``other waste materials'' as 
otherwise used in these definitions.
---------------------------------------------------------------------------

    The term ``fossil fuel normally used in the production of ethanol'' 
means fossil fuel used at the facility in the ethanol production 
process itself, rather than other phases such as trucks transporting 
product, and fossil fuel used to grow and harvest the feedstock. 
Therefore the diesel fuel that trucks consume in hauling wood waste 
from sawmills to the ethanol facility would not be counted in 
determining whether the 90% displacement criterion has been met. We are 
interpreting it in this way because we believe the accounting of fuel 
use associated with transportation and other life cycle activities 
would be extremely difficult and in many cases impossible.\19\
---------------------------------------------------------------------------

    \19\ In Section IX of today's preamble we discuss our analysis 
of the lifecycle fuel impacts of the RFS rule, with respect to 
greenhouse gas (GHG) emissions. While we do account for fuel used in 
hauling materials to ethanol plants in our analysis, we are using 
average nationwide values, rather than data collected for individual 
plants.
---------------------------------------------------------------------------

    Based on the operation of ethanol plants, we are viewing this 
definition to apply to waste materials used to produce thermal energy 
rather than electrical energy. Electrical usage at ethanol plants is 
used for lights and equipment not directly related to the production of 
ethanol. Also, the calculation of fossil fuel used to generate such 
electrical usage would be difficult because it is not always possible 
to track the source of electricity that is purchased off-site. 
Therefore, the final regulations consider displacement of 90 percent of 
fossil fuels at the ethanol plant to mean those fuels consumed on-site 
and that are used to generate thermal energy used to produce ethanol.
    One commenter suggested that electricity from cogeneration (i.e., 
combined heat and power) units be considered in determining the 
percentage of fossil fuel use that is displaced. The commenter claims 
that allowing consideration of electricity use would provide an 
incentive for cogeneration to be used at ethanol plants. Our findings 
regarding the use of electricity at ethanol plants remain the same--
that is, it is not used as part of

[[Page 23917]]

the heat source in ethanol production for economic reasons. We note 
also that the commenter did not present any evidence to the contrary. 
As such, we continue to maintain that electricity is not ``normally 
used in the production of ethanol'' and we are therefore only 
considering the displacement of fossil fuels associated with thermal 
energy at the plant.
    Owners who claim their product qualifies as cellulosic biomass 
ethanol based on the 90 percent fossil fuel displacement through the 
use of waste materials (i.e., animal wastes, and other waste materials) 
are required under today's rule to keep records of fuel (waste-derived 
and fossil fuel) used for thermal energy for verification of their 
claims. They will also be required to track the fossil fuel equivalent 
of any off-site generated waste heat that is captured and which 
displaces fossil fuel used in the ethanol production process. Since 
such waste heat would typically be purchased through agreement with the 
off-site owner, we do not feel it burdensome for owners to track such 
information. Owners will therefore calculate the amount of energy in 
Btu's associated with waste-derived fuels (including the fossil fuel 
equivalent waste heat), and divided by the total energy in Btus used to 
produce ethanol in a given year. Ethanol produced from such facilities 
will get the benefit of the 2.5 ratio. (Section III.D.3.e discusses the 
requirements for owners of facilities that claim to have produced 
cellulosic ethanol under the 90 percent displacement provision, but 
which fail to meet those requirements.)
c. Ethanol That Is Made From the Non-Cellulosic Portions of Animal, 
Other Waste, and Municipal Waste
    ``Waste derived ethanol'' is defined in the Act as ethanol derived 
from ``animal wastes, including poultry fats and poultry wastes, and 
other waste materials; * * * or municipal solid waste.'' Both animal 
wastes and municipal solid waste are also listed as allowable 
feedstocks for the production of ``cellulosic biomass ethanol.'' When 
such feedstocks do not contain cellulose, however, the resulting 
ethanol is waste derived. Both waste-derived and cellulosic ethanol 
both are considered equivalent to 2.5 gallons of renewable fuel when 
determining compliance with the renewable volume obligation.
d. Foreign Producers of Cellulosic and Waste-Derived Ethanol
    Some commenters stated that foreign ethanol producers should not be 
able to have their cellulosic or waste-derived ethanol treated in the 
same manner as domestic cellulosic or waste-derived ethanol under the 
RFS program because of the difficulty in verifying their compliance 
with the provisions discussed above. Today's rule allows such producers 
to participate, provided they meet the requirements discussed in 
Section IV.D.2. of the preamble. The requirements for foreign producers 
of cellulosic or waste-derived ethanol are different than for domestic 
producers and allow for verification of compliance.
2. What Is Biodiesel?
    The Act states that ``The term `renewable fuel' includes * * * 
biodiesel (as defined in section 312(f)) of the Energy Policy Act of 
1992.'' This definition, as modified by Section 1515 of the Energy Act 
states:

    The term ``biodiesel'' means a diesel fuel substitute produced 
from nonpetroleum renewable resources that meets the registration 
requirements for fuels and fuel additives established by the 
Environmental Protection Agency under section 7545 of this title, 
and includes biodiesel derived from animal wastes, including poultry 
fats and poultry wastes, and other waste materials, or municipal 
solid waste and sludges and oils derived from wastewater and the 
treatment of wastewater.

    This definition of biodiesel would include both mono-alkyl esters 
which meet the current ASTM specification D-6751-07 \20\ (the most 
common meaning of the term ``biodiesel'') that have been registered 
with EPA, and any non-esters that are intended for use in engines that 
are designed to run on conventional, petroleum-derived diesel fuel, 
have been registered with the EPA, and are made from any of the 
feedstocks listed above.
---------------------------------------------------------------------------

    \20\ In the event that the ASTM specification D-6751 is 
succeeded with an updated specification in the future, EPA may 
revise the regulations accordingly at such time. Regulations cannot 
be promulgated that only reference ``the most recent version'' of an 
ASTM standard, since doing so would place the American Society for 
Testing and Materials in the position of a regulatory body.
---------------------------------------------------------------------------

    To implement the above definition of biodiesel in the context of 
the RFS rulemaking while still recognizing the unique history and role 
of mono-alkyl esters meeting ASTM D-6751, we have divided the Act's 
definition of biodiesel into two separate parts: Biodiesel (mono-alkyl 
esters) and non-ester renewable diesel. The combination of ``biodiesel 
(mono-alkyl esters)'' and ``non-ester renewable diesel'' in the 
regulations fulfills the Act's definition of biodiesel. Commenters 
supported EPA's approach in defining biodiesel in this manner.
a. Biodiesel (Mono-Alkyl Esters)
    Under today's rule, the term ``biodiesel (mono-alkyl esters)'' 
means a motor vehicle fuel which: (1) Meets the registration 
requirements for fuels and fuel additives established by the 
Environmental Protection Agency under section 7545 of this title (Clean 
Air Act Section 211); (2) is a mono-alkyl ester; (3) meets ASTM 
specification D-6751-07; (4) is intended for use in engines that are 
designed to run on conventional, petroleum-derived diesel fuel, and (5) 
is derived from nonpetroleum renewable resources.
b. Non-Ester Renewable Diesel
    The term ``non-ester renewable diesel'' means a motor vehicle fuel 
which: (1) Meets the registration requirements for fuels and fuel 
additives established by the Environmental Protection Agency under 
section 7545 of this title (Clean Air Act Section 211); (2) is not a 
mono-alkyl ester; (3) is intended for use in engines that are designed 
to run on conventional, petroleum-derived diesel fuel, and (4) is 
derived from nonpetroleum renewable resources. Current examples of a 
non-ester renewable diesel include: ``Renewable diesel'' produced by 
the Neste or UOP process, or diesel fuel produced by processing fats 
and oils through a refinery hydrotreating process.
3. Does Renewable Fuel Include Motor Fuel That Is Made From 
Coprocessing a Renewable Feedstock With Fossil Fuels?
    Renewable fuels can be produced by processing biologically derived 
wastes such as animal fats, as well as other nonpetroleum based 
feedstocks in a traditional refinery--that is, a refinery that normally 
uses crude oil or other fossil fuel-based blendstocks as feeds to 
processing units. Such wastes are pre-processed so that they are in 
liquid form to enable their further processing in units at a 
traditional refinery. In the proposed rule, we defined such feedstocks 
as ``biocrudes'' and included a discussion on how the fuels resulting 
from these feedstocks should be counted. Our basic approach remains the 
same. We have changed the term ``biocrudes'' to ``renewable crudes'', 
since we believe it is more accurate. We are providing additional 
discussion in this preamble on how renewable fuels are made from 
renewable crudes.
    The fuels resulting from the co-processing of the pre-processed 
liquid form of these renewable crudes (i.e., those feedstocks listed in 
the definition of ``renewable fuel'' and, for biodiesel, in the 
statutory definition of ``biodiesel'') in a traditional refinery are

[[Page 23918]]

themselves indistinguishable from the gasoline and diesel products 
produced from crude oil. As such, the treatment of any resulting 
renewable fuel presents a particular complication in terms of RFS 
program compliance--namely, if such fuels are indistinguishable from 
gasoline and diesel produced from crude oil feedstocks, how are the 
volumes to be measured? Also, some renewable feedstocks are used to 
produce renewable diesel (discussed in Section III.B.2 above). In other 
circumstances renewable feedstocks are processed in dedicated 
facilities or units--that is, in either (1) facilities other than 
refineries that process fossil fuels, (2) equipment located within a 
traditional refinery but which is dedicated to renewable feedstocks, or 
(3) equipment located within a traditional refinery that processes 
renewable and conventional feedstocks but solely for the production of 
motor vehicle fuels.
    The processing approach for the renewable feedstock dictates 
whether the resulting fuel is distinguishable from crude oil-based 
fuels by virtue of its being made and stored separately from fossil 
fuels as discussed in further detail below. Therefore, our method for 
counting renewable fuels made from renewable feedstocks differ based on 
how the renewable feedstock is processed
a. Definition of ``Renewable Crudes'' and ``Renewable Crude-Based 
Fuels''
    Under some circumstances renewable feedstocks can be preprocessed 
into a liquid that is similar to petroleum-based feedstocks used in 
traditional refineries. We are classifying such liquids as ``renewable 
crudes,'' and any motor vehicle fuel that is made from such liquids is 
defined broadly as ``renewable crude-based fuel''.
    There are three approaches that can be taken to making renewable 
fuels from renewable crudes. The first would include gasoline or diesel 
products resulting from the processing of renewable crudes in 
production units within refineries that simultaneously process crude 
oil and other petroleum based feedstocks. In these cases, the final 
product consists of a mixture of renewable fuel and fossil-based fuel, 
and may include both motor vehicle fuel and non-motor vehicle fuel. The 
second approach would include diesel and other products resulting from 
processing renewable crudes at a stand-alone facility that does not 
process any fossil fuels, or at a facility dedicated to renewable 
crudes within a traditional refinery.\21\ In this case, a batch of 
renewable crude used as feedstock to a production unit would replace 
crude oil or other petroleum based feedstocks which ordinarily would be 
the feedstock in that process unit. The third approach would be non-
ester renewable diesel fuel produced by processing fats and oils 
through a refinery hydrotreating process. All three approaches can 
produce renewable fuel that is valid for compliance purposes under the 
RFS program, but the measurement of volumes produced and/or their 
associated Equivalence Values may differ.
---------------------------------------------------------------------------

    \21\ Renewable crude-based fuels will need to be registered 
under the provisions contained in 40 CFR 79 Part 4 before they can 
be sold commercially.
---------------------------------------------------------------------------

b. How Are Renewable Crude-Based Fuel Volumes Measured?
    As discussed above, some renewable feedstocks are processed in 
facilities other than refineries, or in equipment located within a 
traditional refinery but which is dedicated to renewable feedstocks. 
The resulting product is ``renewable diesel'' (and such units may in 
the future also produce ``renewable gasoline'' though none is currently 
made in such dedicated facilities). In other situations, renewable 
crudes are coprocessed along with crude oils in traditional refineries, 
resulting in gasoline or diesel products that may be combinations of 
renewable and non-renewable fuels.
    In the case of renewable crude coprocessed with fossil fuels in 
refineries, we are assuming that all of the renewable crude used as a 
feedstock in a refinery unit will end up as a renewable crude-based 
fuel that is valid for RFS compliance purposes. We are taking this 
approach because renewable crudes that are processed through distillate 
hydrotreaters are first pre-processed so that they are in liquid form, 
and such liquid produces diesel fuel in volumes approximately equal to 
the amount that is input to the hydrotreater. We are assuming that 
renewable crudes could also be processed in other process units at 
refineries to make gasoline. The renewable crude processed at a 
refinery is functionally equivalent to crude oil, and the end products 
(gasoline and/or diesel) are indistinguishable from products made from 
crude oil. Thus, rather than requiring the refiner to document what 
portion of the renewable crude-based fuel is renewable fuel, we are 
requiring that the volume of the renewable crude itself count as the 
volume of renewable fuel produced for the purposes of determining the 
volume block codes that are in the RIN (discussed in further detail in 
Section III.D).\22\ The general counting procedure for renewable crude-
based fuels that are not derived through coprocessing with fossil fuels 
is that the volumes of renewable fuel produced are measured directly, 
and an appropriate Equivalence Value is assigned according to the 
methodology discussed in Section III.B.4.
---------------------------------------------------------------------------

    \22\ We are considering the volumes of renewable crude itself, 
not the feedstocks that are made into renewable crude.
---------------------------------------------------------------------------

4. What Are ``Equivalence Values'' for Renewable Fuel?
    One question that EPA needed to address in developing the 
regulations was how to count volumes of renewable fuel in determining 
compliance with the renewable volume obligation. The Act stipulates 
that every gallon of waste-derived ethanol and cellulosic biomass 
ethanol should count as if it were 2.5 gallons for RFS compliance 
purposes. The Act does not stipulate similar values for other renewable 
fuels, but as described below we believe it is appropriate to do so.
    We are requiring that the ``Equivalence Values'' for renewable 
fuels other than those for which specific values are set forth in the 
Act be based on their energy content in comparison to the energy 
content of ethanol, adjusted as necessary for their renewable content. 
The result is an Equivalence Value for corn ethanol of 1.0, for 
biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, and for 
non-ester renewable diesel of 1.7. However, the methodology can be used 
to determine the appropriate equivalence value for any other potential 
renewable fuel as well.
    This section describes why the use of the Equivalence Value 
approach in today's rule is appropriate under the Act, and our 
conclusions regarding the possible future use of lifecycle analyses as 
the basis of Equivalence Values.
 a. Authority Under the Act To Establish Equivalence Values
    We are requiring that Equivalence Values be assigned to every 
renewable fuel to provide an indication of the number of gallons that 
can be claimed for compliance purposes for every physical gallon of 
renewable fuel. An Equivalence Value of 1.0 means that every physical 
gallon of renewable fuel counts as one gallon for RFS compliance 
purposes. An Equivalence Value greater than 1.0 means that every 
physical gallon of renewable fuel counts as more than one gallon for 
RFS compliance

[[Page 23919]]

purposes, while a value less than 1.0 counts as less than one gallon.
    We have interpreted the Act as allowing us to develop Equivalence 
Values according to the methodology discussed below. We believe that 
the use of Equivalence Values based on energy content in comparison to 
the energy content of ethanol is consistent with the intent of Congress 
to treat different renewable fuels differently in different 
circumstances, and to provide incentives for use of renewable fuels in 
certain circumstances, as evidenced by those specific circumstances 
addressed by Congress. The Act has several provisions that provide for 
mechanisms other than straight volume measurement to determine the 
value of a renewable fuel in terms of RFS compliance. For example, 1 
gallon of cellulosic biomass or waste derived ethanol is to be treated 
as 2.5 gallons of renewable fuel. EPA is also required to establish an 
``appropriate amount of credits'' for biodiesel, and to provide for 
``an appropriate amount of credit'' for using more renewable fuels than 
are required to meet your obligation. EPA is also to determine the 
``renewable fuel portion'' of a blending component derived from a 
renewable fuel. These statutory provisions provide evidence that 
Congress did not limit this program solely to a straight volume 
measurement of gallons in the context of the RFS program.
    In response to the NPRM, some commenters supported our view that 
the Act provides sufficient context and direction to permit the use of 
Equivalence Values, while other commenters opposed this view. Some 
parties commented that the methodology proposed in the NPRM did not go 
far enough. These parties argued that instead of energy content, EPA 
should be using lifecycle impacts to set the Equivalence Values. 
Lifecycle analyses are discussed in more detail in Section III.B.4.c.
    Parties that opposed our proposed approach to Equivalence Values 
argued that since the Act did not explicitly give EPA the authority to 
set Equivalence Values for renewable fuels other than cellulosic 
biomass ethanol and waste-derived ethanol, EPA had no authority to do 
so. In their view, the explicit inclusion of a 2.5 credit value for 
cellulosic and waste-derived ethanol and the omission of any credit 
values for other renewables fuels should be taken as evidence that 
Congress intended all other renewable fuels to have Equivalence Values 
of 1.0.
    We disagree that our discretion is so strictly limited. The Act 
specifically gave EPA the authority to determine an ``appropriate'' 
credit for biodiesel, and also establishes a 2.5 value for cellulosic 
biomass ethanol and waste-derived ethanol. As ethanol and biodiesel 
were likely the two primary renewable fuels envisioned in the near-term 
under the Act, it would seem normal for Congress to have focused on 
these. However, Congress also clearly allowed for other renewable fuels 
to participate in the RFS program, and it is appropriate for EPA to 
consider how they should be treated under the Act. Furthermore, in 
addition to the Act's direction that EPA determine an appropriate level 
of credit for biodiesel, the Act also directs EPA to determine the 
``appropriate'' amount of credit for renewable fuel use in excess of 
the required volumes, and to determine the ``renewable fuel portion'' 
of a blending component derived from a renewable fuel. These statutory 
provisions lend further support to our belief that Congress did not 
limit the RFS program solely to a straight volume measurement of 
gallons. Having concluded that it is appropriate to determine an 
appropriate level of credit for biodiesel based on energy content as 
compared to ethanol, EPA is using a consistent approach for other types 
of renewable fuels for which a specific statutory credit value is not 
prescribed.
    Another reason given by parties opposing our approach to 
Equivalence Values was that Equivalence Values higher than 1.0 would 
result in actual volumes of renewable fuel being less than the volumes 
required by the Act. Although it is true that the Act specifies the 
annual volumes of renewable fuel that the program must require and 
directs EPA to promulgate regulations ensuring that gasoline sold each 
year ``contains the applicable volume of renewable fuel,'' the Act also 
contains language that makes the achievement of those volumes 
imprecise. For instance, the deficit carryover provision allows any 
obligated party to fail to meet its RVO in one year if it meets the 
deficit and its RVO in the next year. If many obligated parties took 
advantage of this provision, it could result in the nationwide total 
volume obligation for a particular calendar year not being met. In 
addition, the calculation of the renewable fuel standard is based on 
projected nationwide gasoline volumes provided by EIA (see Section 
III.A). If the projected gasoline volume falls short of the actual 
gasoline volume in a given year, the standard will fail to create the 
demand for the full renewable fuel volume required by the Act for that 
year. The Act contains no provision for correcting for underestimated 
gasoline volumes, and as a result the volumes required by the Act may 
not be consumed in use.
    Some commenters disagreed with our belief that there will only be 
very limited additional situations where an Equivalence Value other 
than 1.0 is used. They expressed concern that the provision for 
Equivalence Values will interfere with meeting the total national 
volume goals for usage of renewable fuel.
    While in the long term we agree that renewable fuels with an 
Equivalence Value greater than 1.0 may grow to become a larger portion 
of the renewable fuel pool, we do not believe that this is likely to be 
the case before 2013, the time period when the statute specifies the 
overall national volumes. EPA will be issuing a new rule prior to 2013, 
and can reconsider its approach to Equivalence Values for renewable 
fuel at that time if it is appropriate to do so. For instance, EIA 
projects that biodiesel volumes will reach 300 million gallons by 2012. 
With the Equivalence Value of 1.5 that we are finalizing today, this 
means that the 7.5 billion gallons required by the Act for 2012 could 
be met with 7.35 billion gallons of renewable fuel. However, this 
result is well within the variability in actual volumes resulting from 
the other statutory provisions described above, and would still result 
in 7.5 billon gallons of ethanol-equivalent (in terms of energy 
content) renewable fuel being consumed. Congress explicitly recognized 
the expected use of credits for biodiesel, as it did for cellulosic 
ethanol. By requiring or authorizing EPA to assign credit values for 
such products, Congress recognized that the national volumes specified 
in the Act would not necessarily be met on a gallon per gallon basis. 
For the very limited number of other renewable fuels not covered by 
these express statutory provisions, assigning an equivalence value is 
consistent with this overall approach. Moreover, EIA is projecting that 
the total volume of renewable fuel will exceed the Act's requirements 
by a substantial margin due primarily to the favorable economics of 
ethanol in comparison to gasoline. Under such projections, the 
existence of renewable fuels with Equivalence Values higher than 1.0 
will have no impact on the demand for renewable fuel.
    Finally, the Act also contains language indicating that EPA has 
flexibility in determining how various renewable fuels should count 
towards meeting the required annual volumes. For instance, valid 
renewable fuels are defined as those that ``replace or reduce the 
quantity of fossil fuel present in a fuel mixture used to operate a 
motor

[[Page 23920]]

vehicle.'' Fossil fuels such as gasoline or diesel are only replaced or 
reduced to the degree that the energy they contain is replaced or 
reduced. We do not believe it would be appropriate to treat a renewable 
fuel with very low volumetric energy content as being equivalent to a 
renewable fuel with very high volumetric energy content, since the 
impact on motor vehicle fossil fuel use is very different for these two 
renewable fuels. The use of Equivalence Values based on volumetric 
energy content helps to achieve this goal.
    A case in point would be butanol. It is produced from the same 
feedstocks as ethanol (i.e., starch crops such as corn) in a similar 
process. However, it results in an alcohol with a higher volumetric 
energy content than ethanol. If we were to give butanol an Equivalence 
Value of 1.0, it would provide an economic disincentive for corn to be 
used to produce butanol instead of ethanol.
    As a result, we continue to believe that the assignment of 
Equivalence Values other than 1.0 to some renewable fuels is a 
reasonable way for the RFS program to establish ``appropriate'' credit 
values while also ensuring that the Act's volume obligations, read 
together with the Act's directions regarding credit values towards 
fulfillment of that obligation, are satisfied. This approach is 
consistent with the way Congress treated the various specific 
circumstances noted above, and thus is basically a continuation of that 
process.
b. Energy Content and Renewable Content as the Basis for Equivalence 
Values
    To appropriately account for the different energy contents of 
different renewable fuels as well as the fact that some renewable fuels 
actually contain some non-renewable content, we are requiring that 
Equivalence Values be calculated using both the renewable content of a 
renewable fuel and its energy content. This section describes the 
calculation methodology for Equivalence Values.
    In order to take the energy content of a renewable fuel into 
account when calculating the Equivalence Values, we must identify an 
appropriate point of reference. Ethanol is a reasonable point of 
reference as it is currently the most prominent renewable fuel in the 
transportation sector, and it is likely that the authors of the Act saw 
ethanol as the primary means through which the required volumes would 
be met in at least the first years of the RFS program. By comparing 
every renewable fuel to ethanol on an equivalent energy content basis, 
each renewable fuel is assigned an Equivalence Value that precisely 
accounts for the amount of petroleum in motor vehicle fuel that is 
reduced or replaced by that renewable fuel in comparison to ethanol. To 
the degree that corn-based ethanol continues to dominate the pool of 
renewable fuel, this approach allows actual volumes of renewable fuel 
to be consistent with the volumes required by the Act.
    Equivalence Values also account for the renewable content of 
renewable fuels, since the presence of any non-renewable content 
impairs the ability of the renewable fuel to replace or reduce the 
quantity of fossil fuel present in a fuel mixture used to operate a 
motor vehicle. The Act specifically states that only the renewable fuel 
portion of a blending component should be considered part of the 
applicable volume under the RFS program. As described in more detail 
below, we have interpreted this to mean that every renewable fuel 
should be evaluated at the molecular level to distinguish between those 
molar fractions that were derived from a renewable feedstock, versus 
those molar fractions that were derived from a fossil fuel feedstock. 
Along with energy content in comparison to ethanol, the relative energy 
fraction of renewable versus non-renewable content is thus used 
directly as the basis for the Equivalence Value.
    We are requiring that the calculation of Equivalence Values 
simultaneously take into account both the renewable content of a 
renewable fuel and its energy content in comparison to denatured 
ethanol. To accomplish this, we are requiring the following formula:

EV = (RRF / REth) x (ECRF / 
ECEth)

Where:

EV = Equivalence Value for the renewable fuel.
RRF = Renewable content of the renewable fuel, in percent 
of molecular energy.
REth = Renewable content of denatured ethanol, in percent 
of molecular energy.
ECRF = Energy content of the renewable fuel, in Btu per 
gallon (LHV).
ECEth = Energy content of denatured ethanol, in Btu per 
gallon (LHV).

    Instead of the higher heating value, the lower heating value (LHV) 
is used to represent energy content because it more accurately reflects 
the energy available in the fuel to produce work.
    R is a measure of that portion of the renewable fuel molecules 
which can be considered to have come from a renewable source. Since R 
(that is, RRF and REth) is being combined with 
relative energy content in the formula above, the value of R cannot be 
based on the weight fraction of the atoms in the molecule which came 
from a renewable feedstock (the ``renewable atoms''), but rather must 
be based on the energy inherent in that portion of the molecules 
comprised of renewable atoms. To identify the renewable atoms within 
the molecules that comprise the renewable fuel, we must examine the 
chemical process through which the renewable fuel was produced. A 
detailed explanation of calculations for R and several examples are 
given in a technical memorandum in the docket.\23\
---------------------------------------------------------------------------

    \23\ ``Calculation of equivalence values for renewable fuels 
under the RFS program'', memo from David Korotney to EPA Air Docket 
OAR-2005-0161.
---------------------------------------------------------------------------

    In the case of ethanol, denaturants are added to preclude the 
ethanol's use as food. Denaturants are generally a fossil-fuel based, 
gasoline-like hydrocarbon in concentrations of 2-5 volume percent, with 
5 percent being the most common historical level. One commenter argued 
that the Equivalence Value of ethanol must be specified as 0.95 for 
this very reason. However, as described in the NPRM, we believe that 
the Equivalence Value for ethanol should be specified as 1.0 despite 
the presence of a denaturant. First, as stated above, ethanol is 
expected to dominate the renewable fuel pool for at least the next 
several years, and it is likely that the authors of the Act recognized 
this fact. Thus it seems likely that it was the intent of the authors 
of the Act that each physical gallon of denatured ethanol be counted as 
one gallon for RFS compliance purposes. Second, the accounting of 
ethanol has historically ignored the presence of the denaturant. For 
instance, under Internal Revenue Service (IRS) regulations the 
denaturant can be counted as ethanol by parties filing claims to the 
IRS for the federal excise tax credit. Also, EIA reporting requirements 
for ethanol producers allow them to include the denaturant in their 
reported volumes. The commenter arguing for the use of an Equivalence 
Value of 0.95 for ethanol provided no additional information to counter 
these arguments.
    Since we are requiring that denatured ethanol be assigned an 
Equivalence Value of 1.0, this must be reflected in the values of 
REth and ECEth. We have calculated these values 
to be 93.1 percent and 77,550 Btu/gal, respectively. Details of these 
calculations can be found in the aforementioned technical memorandum to 
the docket. The final equation to be used for calculation of 
Equivalence Values is therefore:

EV = (R / 0.931) * (EC / 77,550)

Where:

EV = Equivalence Value for the renewable fuel.

[[Page 23921]]

R = Renewable content of the renewable fuel, expressed as a percent, 
on an energy basis, of the renewable fuel that comes from a 
renewable feedstock.
EC = Energy content of the renewable fuel, in Btu per gallon (lower 
heating value).

    For the specific case of biogas which cannot be measured in 
volumetric units, we are specifying that 77,550 Btu of biogas will be 
considered to be the equivalent of one gallon of renewable fuel.
    The calculation of the Equivalence Value for a particular renewable 
fuel can lead to values that deviate only slightly from 1.0, and/or can 
have varying degrees of precision depending on the uncertainty in the 
value of R or ECRF. In the NPRM we proposed several 
simplifications to streamline the application of Equivalence Values in 
the context of the RFS program. These included the use of pre-specified 
bins, rounding, and the use of an Equivalence Value of 1.0 when the 
calculated value was close to 1.0. We received some comments suggesting 
that these three simplifications unnecessarily complicated the 
determination of Equivalence Values. Based on comments received, we 
have determined for the final rule to simplify the application of 
Equivalence Values by only requiring the calculated values be rounded 
to the first decimal place. Also, based on consideration of comments 
received on how such products should be counted, for renewable diesel 
produced by processing fats and oils through a refinery hydrotreating 
process, we have determined that the default Equivalence Value should 
be 1.7 consistent with renewable diesel produced through other 
processes. This approach recognizes that hydrotreating produces a 
product consistent with our definition of non-ester renewable diesel. 
Furthermore, based on comments received, the volume of the final 
product is expected to be comparable to the volume of the input 
renewable crude. Therefore, the volume of renewable crude will be used 
as a surrogate for the volume of the final product. With the exception 
of renewable diesel produced through hydroteating fats or oils which is 
identical to renewable diesel, none of the specific Equivalence Values 
proposed in the NPRM have changed as a result of this simplification. 
The final values are shown in the table below.

      Table III.B.4-1.--Equivalence Values for Some Renewable Fuels
------------------------------------------------------------------------
                                                             Equivalence
                                                              value (EV)
------------------------------------------------------------------------
Cellulosic biomass ethanol or waste-derived ethanol \24\...         2.5
Ethanol from corn, starches, or sugar......................         1.0
Biodiesel (mono alkyl ester)...............................         1.5
Non-ester renewable diesel and hydrotreated renewable               1.7
 crudes....................................................
Butanol....................................................         1.3
Renewable crude-based fuels................................         1.0
------------------------------------------------------------------------

    Consistent with the NPRM, the Equivalence Value for renewable 
crude-based fuels is 1.0. Although some renewable crude-based fuels 
might warrant a higher value based on their energy content, it is also 
likely that some of the renewable crude does not end up as a motor 
vehicle fuel. Rather than requiring the refiner to document what 
portion of the biocrude-based renewable fuel is other than diesel or 
gasoline (e.g., jet fuel), we are combining the Equivalence Value of 
1.0 with a requirement that the volume of the renewable crude itself 
count as the volume of renewable fuel produced for the purposes of 
determining the volume block codes that are in the RIN (discussed in 
further detail in Section III.D). While this approach may result in 
some products such as jet fuel being counted as renewable fuel, we 
believe the majority of the products produced will be motor vehicle 
fuel because we assume refiners who elect to use biocrudes would do so 
to help meet the requirements of this rule. Furthermore, both diesel 
and gasoline presently make up about 85 percent of the product slate of 
refineries on average. This amount that has been steadily increasing 
for over time, and we expect that the percentage will continue to 
increase as demand for gasoline and diesel increases. Thus the 
designation of an Equivalence Value of 1.0 balances out the potentially 
higher energy content of renewable crude-based fuels with the potential 
for lower yields of renewable fuel produced as motor vehicle fuel. We 
received no comment on this issue and are finalizing it as proposed.
---------------------------------------------------------------------------

    \24\ The 2.5 value is specified by the Energy Act, and is not 
based on the EV formula discussed earlier.
---------------------------------------------------------------------------

    Since there are a wide variety of possible renewable fuels that 
could qualify under the RFS program, there may be cases in which a 
party produces a renewable fuel not shown in Table III.B.4-1. A party 
may also produce a renewable fuel listed in the above table, but which 
has a different renewable content or energy content than the values 
assumed for our calculations. For such cases we have created a 
regulatory mechanism through which the producer may submit a petition 
to the Agency describing the renewable fuel, its feedstock and 
production process, and the calculation of its Equivalence Value. The 
Agency will review the petition and approve an appropriate Equivalence 
Value based on the information provided. We will publish newly assigned 
Equivalence Values in the Federal Register at the same time as the 
annual standard is published each November.
    In the NPRM, we also described an additional approach to setting 
the Equivalence Value for biodiesel (mono alkyl esters). Since ethanol 
derived from waste products such as animal wastes and municipal solid 
waste will be assigned an Equivalence Value of 2.5 based on a 
requirement in the Act, we pointed out that it might be appropriate to 
create a parallel provision for biodiesel made from wastes. Under this 
approach, biodiesel made from waste products would have been assigned 
an Equivalence Value of 2.5 through 2012. Supporters of 2.5 Equivalence 
Value argued that it would place the treatment of waste-derived 
biodiesel on the same level as waste-derived ethanol, and that it would 
be good Agency policy to encourage and reward parties that turn 
materials that would otherwise be wasted into usable motor vehicle 
fuel. While some of these arguments may have merit, we nevertheless 
believe that it is most appropriate to maintain the general methodology 
applicable to renewable fuels at this time and reserve the 2.5:1 
valuation for just the fuel specified by Congress. Therefore, we have 
not finalized a 2.5 Equivalence Value for waste-derived biodiesel.
    For the specific case of ETBE, we have chosen for this final rule 
to eliminate a uniquely determined Equivalence Value. As described in 
Section III.D.2.b, ETBE is generally made from ethanol to which RINs 
will have already been assigned. An ETBE producer, therefore, would 
need only assign the RINs received with the ethanol to the ETBE made 
from that ethanol. In this case, there will be no need to generate new 
RINs, and therefore no need for a separate Equivalence Value.
    Except for cellulosic biomass ethanol and waste-derived ethanol, 
the Equivalence Values shown in Table III.B.4-1, or any others approved 
through the petition process, will be applicable for all years. 
However, beginning in 2013, the 2.5 to 1 ratio no longer applies for 
cellulosic biomass

[[Page 23922]]

ethanol. The Act is unclear about whether the 2.5 to 1 ratio for waste-
derived ethanol will apply after 2012, though it might be appropriate 
to treat cellulosic biomass ethanol and waste-derived ethanol in a 
consistent manner. Nevertheless, in the subsequent rulemaking mentioned 
above, we will address this issue explicitly. In today's final rule we 
are only specifying the ratio for cellulosic biomass and waste-derived 
ethanol prior to 2013.
c. Lifecycle Analyses as the Basis for Equivalence Values
    In the NPRM we also described an alternative approach in which 
Equivalence Values for renewable fuels would be based on lifecycle 
analyses. We described both the merits and challenges associated with 
such an approach and requested comment. Based on the comments received 
we continue to believe that lifecycle analyses could provide a means of 
reflecting the relative benefits of one renewable fuel in comparison to 
another. However, we are not, in this action, establishing Equivalence 
Values on a lifecycle basis. Rather, we intend to continue evaluating 
and updating the tools and assumptions associated with lifecycle 
analyses in a collaborative effort with stakeholders. This rulemaking 
makes no determination and should not be interpreted to make any 
determination regarding whether EPA has the legal authority under 
section 1501 of the Energy Act, as incorporated in section 211(o) of 
the Clean Air Act, to use lifecycle analysis in establishing 
Equivalence Values in general or Equivalence Values specifically 
related to greenhouse gas or carbon dioxide emissions. This section 
describes some of the comments we received on the use of lifecycle 
analyses and our responses.
    Lifecycle analyses involve an examination of fossil fuel used, and 
emissions generated, at all stages of a renewable fuel's life. A 
typical lifecycle analysis examines production of the feedstock, its 
transport to a conversion facility, the conversion of the feedstock 
into renewable motor vehicle fuel, and the transport of the renewable 
fuel to the consumer. At each stage, every activity that consumes 
fossil fuels or results in emissions is quantified, and these energy 
consumption and emission estimates are then summed over all stages. By 
accounting for every activity associated with renewable fuels over 
their entire life, we can assess renewable fuels in terms of not just 
their impact within the transportation sector, but across all sectors 
and thus for the nation as a whole. In this way, lifecycle analyses 
provide a more complete picture of the potential impacts of different 
fuels or different fuel sources. While the use of energy content to 
establish Equivalence Values is an improvement over a simple gallon-
for-gallon approach, a lifecycle basis would provide a further level of 
sophistication in assessing the net energy input and output of fuels 
and the emissions associated with the use of different fuels.
    Supporters of the use of lifecycle analyses for setting the 
Equivalence Values of different renewable fuels pointed to several 
advantages of this approach. First, doing so could create an incentive 
for obligated parties to choose renewable fuels having a greater 
ability to reduce fossil fuel use or resulting emissions, since such 
renewable fuels would have higher Equivalence Values and thus greater 
value in terms of compliance with the RFS requirements. The 
preferential demand for renewable fuels having higher Equivalence 
Values could in turn spur additional growth in production of these 
renewable fuels. Second, using lifecycle analyses as the basis for 
Equivalence Values could orient the RFS program more explicitly towards 
reducing petroleum use, fossil fuel use or emissions.
    However, the use of lifecycle analyses to establish the Equivalence 
Values for different renewable fuels also raises a number of issues, 
generally acknowledged by supporters of the use of lifecycle analyses. 
For instance, lifecycle analyses can be conducted using several 
different metrics, including total fossil fuel consumed, petroleum 
energy consumed, regulated pollutant emissions (e.g., VOC, 
NOX, PM), carbon dioxide emissions, or greenhouse gas 
emissions. Each metric would result in a different set of Equivalence 
Values. At the present time there is no consensus on which metric would 
be most appropriate for this purpose or the purposes of the Act.
    There is also no consensus on the approach to lifecycle analyses 
themselves. Although we have chosen to base our lifecycle analyses on 
Argonne National Laboratory's GREET model for the reasons described in 
Section IX, there are a variety of other lifecycle models and analyses 
available. The choice of model inputs and assumptions all have a 
bearing on the results of lifecycle analyses, and many of these 
assumptions remain the subject of debate among researchers. Lifecycle 
analyses must also contend with the fact that the inputs and 
assumptions generally represent industry-wide averages even though 
energy consumed and emissions generated vary widely from one facility 
or process to another.
    There currently exists no organized, comprehensive dialogue among 
stakeholders about the appropriate tools and assumptions behind any 
lifecycle analyses. We will be initiating more comprehensive 
discussions about lifecycle analyses with stakeholders in the near 
future.
    Another issue related to using lifecycle analyses as the basis for 
Equivalence Values pertains to the ultimate impact that the RFS program 
would have on petroleum use, fossil fuel use, regulated pollutant 
emissions, and/or emissions of GHGs. With a fixed volume of renewable 
fuel required under the RFS program, any renewable fuel with an 
Equivalence Value greater than 1.0 would necessarily mean that fewer 
actual gallons would be needed to meet the RFS standard. Thus, the 
advantage per gallon may be offset with fewer overall gallons, 
resulting in no overall additional benefit under the chosen metric for 
using fuels with higher Equivalence Values unless the RFS standard was 
simultaneously adjusted by Congress.
    Based on comments received in response to our NPRM, we continue to 
believe that the current state of scientific inquiry surrounding 
lifecycle analyses is not sufficiently robust to warrant its use to set 
Equivalence Values in this final rule. Since renewable fuel use is 
expected to far exceed the standards being finalized today, a higher 
equivalence value for those renewables with greater lifecycle benefits 
will likely do little to stimulate their use. However, if in the future 
the RFS standard more closely matches renewable demand, this could be 
important. We are committed to continuing our investigations into 
lifecycle analyses.

C. What Gasoline Is Used To Calculate the Renewable Fuel Obligation and 
Who Is Required To Meet the Obligation?

1. What Gasoline Is Used To Calculate the Volume of Renewable Fuel 
Required To Meet a Party's Obligation?
    The Act requires EPA to promulgate regulations designed to ensure 
that ``gasoline sold or introduced into commerce in the United States 
(except in noncontiguous states or territories)'' contains on an annual 
average basis, the applicable aggregate volumes of renewable fuels as 
prescribed in the Act.\25\ To implement this provision, today's final 
rule provides that the volume of gasoline used to determined the 
renewable fuel obligation must include all finished gasoline (RFG and

[[Page 23923]]

conventional) produced or imported for use in the contiguous United 
States during the annual averaging period and all unfinished gasoline 
that becomes finished gasoline upon the addition of oxygenate blended 
downstream from the refinery or importer. This would include both 
unfinished reformulated gasoline, called ``reformulated gasoline 
blendstock for oxygenate blending,'' or ``RBOB,'' and unfinished 
conventional gasoline designed for downstream oxygenate blending (e.g. 
sub-octane conventional gasoline), called ``CBOB.'' The volume of any 
other unfinished gasoline or blendstock, such as butane, is not 
included in the volume used to determine the renewable fuel obligation, 
except where the blendstock is combined with other blendstock or 
finished 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 is 
included in the volume used to determine the renewable fuels obligation 
for the blender. Where a blendstock is added to finished gasoline, only 
the volume of the blendstock is included, since the finished gasoline 
would have been included in the compliance determinations of the 
refiner or importer of the gasoline.
---------------------------------------------------------------------------

    \25\ CAA Section 211(o)(2)(A)(i), as added by Section 1501(a) of 
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Gasoline produced or imported for use in a noncontiguous state or 
U.S. territory \26\ is not included in the volume used to determine the 
renewable fuel obligation (unless the noncontiguous state or territory 
has opted-in to the RFS program), nor is gasoline, RBOB or CBOB 
exported for use outside the United States.
---------------------------------------------------------------------------

    \26\ The noncontiguous states are Alaska and Hawaii. The 
territories are the Commonwealth of Puerto Rico, the U.S. Virgin 
Islands, Guam, American Samoa, and the Commonwealth of the Northern 
Marianas.
---------------------------------------------------------------------------

    For purposes of this preamble, the various gasoline products (as 
described above) that are included in the volume of gasoline used to 
determine the renewable fuel obligation are collectively called 
``gasoline.''
    The final rule excludes the volume of renewable fuels contained in 
gasoline from the volume of gasoline used to determine the renewable 
fuels obligation. In implementing the Act's renewable fuels 
requirement, our primary goal was to design a program that is simple, 
flexible and enforceable. If the program were to include renewable 
fuels in the volume of gasoline used to determine the renewable fuel 
obligation, then every blender that blends ethanol downstream from the 
refinery or importer would be subject to the renewable fuel obligation 
for the volume of ethanol that they blend. There are currently 
approximately 1,200 such ethanol blenders. Of these blenders, only 
those who blend ethanol into RBOB are regulated parties under current 
fuels regulations. Designating all of these ethanol blenders as 
obligated parties under the RFS program would greatly expand the number 
of regulated parties and increase the complexity of the RFS program 
beyond that which is necessary to carry out the renewable fuels mandate 
under the Act.
    The Act provides that the renewable fuel obligation shall be 
``applicable to refiners, blenders, and importers, as appropriate.'' 
\27\ For the reasons discussed above, we believe it is appropriate to 
exclude downstream renewable fuel blenders from the group of parties 
subject to the renewable fuel obligation and to exclude renewable fuels 
from the volume of gasoline used to determine the renewable fuel 
obligation. 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 downstream from the refinery or importer would be excluded 
from the volume of gasoline used to determine the obligation. Any non-
renewable fuel added downstream, however, would be included in the 
volume of gasoline used to determine the obligation. This approach has 
no impact on the total volume of renewable fuels required (which is 
specified in the Act and must be met regardless of the approach taken 
here), but merely on the number of obligated parties. As discussed 
earlier, this volume of renewable fuel is likewise excluded from the 
calculation performed each year by EPA to determine the applicable 
percentage.
---------------------------------------------------------------------------

    \27\ CAA Section 211(o)(3)(B), as added by Section 1501(a) of 
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    The NPRM was unclear with regard to whether obligated parties are 
to determine their renewable fuel obligation based on the gasoline 
production of all of their facilities in the aggregate, or each 
facility individually. As discussed above, EPA has discretion under the 
Energy Act to determine the renewable fuels obligation applicable to 
parties, ``as appropriate.'' We believe that allowing obligated parties 
to determine their obligation based on either their facilities in the 
aggregate or individually is appropriate, since allowing this 
flexibility will not affect compliance with the RFS. Although some 
commenters expressed concern that obligated parties with multiple 
facilities could gain an economic advantage over obligated parties with 
only a single facility if aggregate compliance is allowed, we do not 
believe that this will be the case given the unrestricted trading 
allowed under our program. We also believe that clarification in the 
regulations regarding the basis on which the obligation may be 
determined is a necessary and logical outgrowth of the proposal. As a 
result, the regulations have been modified in the final rule to clarify 
that the renewable fuels obligation may be determined based on the 
gasoline production of all of an obligated party's facilities in the 
aggregate, or each facility individually.
    We received comment that EPA should clarify when obligated parties 
must include imported gasoline that is used as ``gasoline treated as 
blendstock'', or GTAB, in the volume of gasoline used to determine the 
party's renewable fuel obligation. As stated in the preamble to the 
proposed rule, GTAB is to be treated as a blendstock with regard to the 
RFS rule. Where the GTAB is blended with other blendstock (other than 
only renewable fuel) to produce gasoline, the total volume of the 
gasoline blend, including the GTAB, is 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 is 
included in the volume of gasoline used to determine the renewable fuel 
obligation (since the finished gasoline will already be included in the 
RFS calculations of the refiner of that gasoline). For purposes of 
compliance demonstrations, the RFS rule treats GTAB in a manner that is 
consistent with the reformulated gasoline (RFG) and conventional 
gasoline (CG) regulations. Under the RFG/CG regulations, importers who 
designate imported gasoline as GTAB must be registered with EPA as both 
an importer and a refiner. The importer submits separate compliance 
reports to EPA, one in its capacity as an importer, and one in its 
capacity as a refiner. The GTAB is blended by the importer and included 
in the importer's compliance calculations in its capacity as a refiner 
of the GTAB, and is excluded from the importer's compliance 
calculations in its capacity as an importer. The RFS rule treats GTAB 
in a similar manner; i.e., the importer includes the GTAB in the volume 
of gasoline used to determine the renewable fuel obligation of the 
importer in its capacity as a refiner of the GTAB, and excludes the 
GTAB in the volume of gasoline used to

[[Page 23924]]

determine the renewable fuel obligation of the importer in its capacity 
as an importer. The regulations have been clarified with regard to how 
GTAB is used to determine the GTAB importer's renewable fuels 
obligation.
    We received comment that EPA should clarify that the terms RBOB and 
CBOB include ``blendstocks for oxygenate blending'' that are designed 
to comply with state fuels requirements, such as CARBOB (California), 
AZRBOB (Arizona), and LVBOB (Las Vegas). As discussed in Section 
III.C.1, all gasoline, and all unfinished gasoline that becomes 
finished gasoline upon the addition of oxygenate, that is produced or 
imported for use in the contiguous United States is included in the 
volume of gasoline used to determine an obligated party's renewable 
fuels obligation. As such, any finished gasoline, or unfinished 
gasoline that becomes finished gasoline upon the addition of oxygenate, 
that is produced or imported to comply with state fuels programs must 
also be included in the volume of gasoline used to determine an 
obligated party's renewable fuels obligation. The regulations have been 
clarified in this regard.
2. Who Is Required To Meet the Renewable Fuels Obligation?
    Under the final rule, any person who meets the definition of 
refiner under the fuels regulations, which includes any blender who 
produces gasoline by combining blendstocks or blending blendstocks into 
finished gasoline, is subject to the renewable fuels obligation. Any 
person who brings gasoline into the 48 contiguous states from a foreign 
country or from an area that has not opted-in to the RFS program, or 
brings gasoline from a foreign country or an area that has not opted-in 
to the RFS program into an area that has opted-in to the RFS program, 
is considered an importer under the RFS program and is subject to the 
renewable fuels obligation. As noted above, a blender who only blends 
renewable fuels downstream from the refinery or importer is not subject 
to the renewable fuel obligation. Any person that is required to meet 
the renewable fuels obligation is called an ``obligated party.'' We 
generally refer to all of the obligated parties as refiners and 
importers, since the covered blenders are all refiners under the 
regulations.
    A refiner or importer located in a noncontiguous state or U.S. 
territory is not subject to the renewable fuel obligation and thus is 
not an obligated party (unless the noncontiguous state or territory 
opts-in to the RFS program). A party located within the contiguous 48 
states is an obligated party if it ``imports'' into the 48 states any 
gasoline produced or imported by a refiner or importer located in a 
noncontiguous state or territory.
    We received comment that EPA should clarify how the RFS rule 
applies to transmix processors and blenders. Transmix processors and 
blenders are treated like any other blenders under the RFS rule. 
Transmix processors are parties that separate the gasoline portion of 
the transmix from the transmix and either sell the gasoline portion as 
finished gasoline or blend it with other components to produce 
gasoline. Transmix processors exclude the gasoline portion of the 
transmix from the volume that is used to determine the party's 
renewable fuel obligation, since the gasoline portion of the transmix 
would have been included in the volume used to determine the renewable 
fuels obligation of the refiner or importer of the gasoline. In 
calculating the volume used to determine its renewable fuel obligation, 
the transmix processor would include any blendstocks (other than 
renewable fuels) that are added to the gasoline separated from the 
transmix. Where the transmix processor combines the gasoline portion of 
the transmix with purchased finished gasoline, both the gasoline 
portion of the transmix and the finished gasoline would be excluded, 
since the finished gasoline would have been included in the volume used 
to determine the renewable fuels obligation of the refiner or importer 
of the finished gasoline. Transmix blenders are parties that blend 
small amounts of unprocessed transmix into gasoline. Transmix blenders 
are not obligated parties if they only blend transmix into finished 
gasoline. If the transmix blender adds blendstocks to the transmix, the 
transmix blender would be an obligated party with regard to the volume 
of blendstocks added. The regulations have been clarified with regard 
to how the RFS rule applies to transmix processors and blenders.
3. What Exemptions Are Available Under the RFS Program?
a. Small Refinery and Small Refiner Exemption
    The Act provides an exemption from the RFS standard for small 
refineries during the first five years of the program. The Act defines 
small refinery as ``a refinery for which the average aggregate daily 
crude oil throughput for a calendar year (as determined by dividing the 
aggregate throughput for the calendar year by the number of days in the 
calendar year) does not exceed 75,000 barrels.'' \28\ Thus, any 
gasoline produced at a refinery that qualifies as a small refinery 
under this definition is not counted in determining the renewable fuel 
obligation of a refiner until January 1, 2011. Where a refiner complies 
with the renewable fuel obligation on an aggregate basis for multiple 
refineries, the refiner may exclude from its compliance calculations 
gasoline produced at any refinery that qualifies as a small refinery 
under the RFS program. This exemption applies to any refinery that 
meets the definition of small refinery stated above regardless of the 
size of the refining company that owns the refinery. Based on 
information currently available to us we expect 42 small refineries to 
qualify for this exemption. Beginning in 2011, small refineries will be 
required to meet the same renewable fuel obligation as all other 
refineries, unless their exemption is extended pursuant to Sec.  
80.1141(e).
---------------------------------------------------------------------------

    \28\ CAA Section 211(o)(a)(9), as added by Section 1501(a) of 
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    In addition to small refineries as defined in the Act, we proposed 
to extend this relief to refiners who, during 2004: (1) Produced 
gasoline at a refinery by processing crude oil through refinery 
processing units; (2) employed an average of no more than 1,500 people, 
including all employees of the small refiner, any parent company and 
its subsidiary companies; and (3) had a total average crude oil 
processing capability for all of the small refiner's refineries of 
155,000 barrels per calendar day (bpcd). These size criteria were 
established in prior rulemakings and were the result of our analyses of 
small refiner impacts. Based on information currently available to us, 
we believe that there are only three gasoline refineries owned by small 
refiners that meet these criteria and that currently exceed the 75,000 
bpcd crude oil processing capability defined by the Act.
    We received comments supporting the proposed extension of the small 
refinery exemption to small refiners, and we also received comments 
opposing the proposed provision. Commenters that supported the 
provision generally stated that they believe that a small refiner 
exemption is necessary as those entities (i.e., companies) that would 
qualify as small refiners are generally at an economic disadvantage due 
to their company size--whereas the Act only recognizes facilities, 
based on the size of each location. These commenters also stated that 
they have concerns with the cost and the availability of credits under 
this program, and believe that provisions for small refiners are

[[Page 23925]]

necessary to help mitigate any significant adverse economic impact on 
these entities. Commenters that opposed the provision stated that they 
believe that EPA exceeded its discretionary authority, that there 
appears to be no basis on which the Agency can legitimately expand this 
statutory exemption to add small refiners, and that Congress ``clearly 
did not intend that the exemption be broadened to also include small 
refiners.'' One commenter also stated that it does not believe that 
small refiner provisions are necessary because this rule does not 
require costly capital investments like previous fuel regulations.
    As stated in the proposal, we believe that we have discretion in 
determining an appropriate lead-time for the start-up of this program, 
as well as discretion to determine the regulated refiners, blenders and 
importers, ``as appropriate.'' We continue to believe that some 
refiners, due to their size, generally face greater challenges compared 
to larger refiners. The Small Business Regulatory Enforcement Fairness 
Act (SBREFA) also recognizes this and requires agencies, during 
promulgation of new standards, to assess the potential impacts on small 
businesses (as defined by the Small Business Administration (SBA) at 13 
CFR 121.201). For those instances where the Agency cannot certify that 
a rule will not have a significant economic impact on a substantial 
number of small entities, we are required to convene a SBREFA Panel. A 
SBREFA Panel process--which generally takes at least six months to 
complete--entails performing outreach with entities that meet the 
definition of a small business to develop ways to mitigate potential 
adverse economic impacts on small entities, in consultation with SBA 
and the Office of Management and Budget (OMB).
    ``Small refiners'' have historically been recognized in EPA fuel 
regulations as those refiners who employ no more than 1,500 employees 
and have an average crude oil capacity of 155,000 bpcd. These refiners 
generally have greater difficulty in raising and securing capital for 
investing in capital improvements and in competing for engineering 
resources and projects. This rulemaking does not require that refiners 
make capital improvements, however there are still significant costs 
associated with meeting the standard. While we were not required to 
assess the impacts on small businesses under the Energy Policy Act, we 
are required to do so under SBREFA. Based on our own analysis and 
outreach with small refiners, our assessment is that this rule will not 
impose a significant adverse economic impact on small refiners if they 
are given the small refinery exemption. Further, as noted above, we 
believe that no more than three additional refiners that do not meet 
the Energy Policy Act's definition of a small refinery will qualify as 
small refiners for this rule. Therefore, we are finalizing the proposed 
provision that the small refinery exemption will be provided to 
qualified small refiners. This exemption does not mean that less 
renewable fuel will be used than is required in the Energy Policy Act; 
rather, it just means that small refiners will not be obligated to 
ensure that those volumes are attained during the period of their 
exemption.
    We also proposed to allow foreign refiners to apply for a small 
refinery or small refiner exemption under the RFS program. We requested 
comment on the provision and related aspects, and we received some 
comments in which commenters stated that they believe that there is no 
reason to extend the small refinery exemption to these refiners. One 
commenter even stated that it believes that such an allowance would be 
unlawful. We proposed this provision for consistency with prior 
gasoline-related fuel programs (anti-dumping, MSAT, and gasoline 
sulfur) which allowed foreign refiners to receive such exemptions, and 
we are finalizing the provision in this action. Under this provision, 
foreign small refiners and foreign small refineries can apply for an 
exemption from the RFS standards such that importers would not count 
the small refiner or small refinery gasoline volumes towards the 
importer's renewable volume obligation. The Energy Policy Act does not 
prohibit EPA from granting this avenue of relief to foreign entities, 
and EPA believes it is consistent with the spirit of international 
trade agreements to provide it.
    In the proposal we stated that applications for a small refinery 
exemption must be received by EPA by September 1, 2007 for the 
exemption to be effective in 2007 and subsequent calendar years. We 
proposed that the application should include documentation that the 
small refinery's average aggregate daily crude oil throughput for 
calendar year 2004 did not exceed 75,000 barrels; and that eligibility 
would be based on 2004 data (rather than 2005). Further, we proposed 
that the small refinery exemption would be effective 60 days after 
receipt of the application by EPA unless EPA notifies the applicant 
that the application was not approved or that additional documentation 
is required. We received comments on this provision in which commenters 
stated that requiring small refinery applications was inconsistent with 
the language set out in the Act. The commenters stated that small 
refineries should not be obligated parties in 2007 even if they do not 
submit a small refinery application by September 1, 2007. We agree with 
these statements, and believe that the Energy Policy Act did in fact 
intend to provide this exemption without the need for small refineries 
to submit applications. However, in order to ensure that this provision 
is not being misused, we believe that it is necessary for refiners to 
verify that their refineries meet the definition set out in the Act. 
Therefore, we are finalizing that the small refinery exemption will 
become active immediately upon the effective date of the rule. Refiners 
will only be required to send a letter to EPA verifying their status as 
a small refinery. We did not receive any comments on our proposal to 
base eligibility on 2004 data, nor did we receive comments on whether a 
multiple-year average should be used. We believe that eligibility 
should be based on 2004 data rather than on 2005 data, since it was the 
first full year prior to passage of the Energy Act. In addition, some 
refineries' production may have been affected by Hurricanes Katrina and 
Rita in 2005. We are thus finalizing our proposed approach to base 
eligibility on 2004 data.
    As discussed above, we proposed that refiners that do not qualify 
for a small refinery exemption under the 75,000 bpcd criteria, but 
nevertheless meet the criteria of a small refiner may apply for small 
refiner status under the RFS rule. We proposed that the applications 
must be received by EPA by September 1, 2007 for the exemption to be 
effective in 2007 and subsequent calendar years (similar to the small 
refinery exemption). We also proposed that small refiner status would 
be determined based on documentation submitted in the application which 
demonstrates that the refiner met the criteria for small refiner status 
during the calendar year 2004 and that EPA would notify a refiner of 
approval or disapproval of small refiner status by letter.
    The final rule provides that qualified small refiners receiving the 
small refinery exemption will also receive the exemption immediately 
upon the effective date of the rule. These refiners must also submit a 
verification letter showing that they meet the small refiner criteria. 
This letter will be similar to the small refiner applications required 
under other EPA fuel programs (and must contain all the required 
elements

[[Page 23926]]

specified in the regulations at Sec.  80.1142), except the letter will 
not be due prior to the program. Small refiner status verification 
letters for this rule that are later found to contain false or 
inaccurate information will be void as of the effective date of these 
regulations. Unlike the case for small refineries, small refiners who 
subsequently do not meet all of the criteria for small refiner status 
(i.e., cease producing gasoline by processing crude oil, employ more 
than 1,500 people or exceed the 155,000 bpcd crude oil capacity limit) 
as a result of a merger with or acquisition of or by another entity are 
disqualified as small refiners, except in the case of a merger between 
two previously approved small refiners. As in other EPA programs, where 
such disqualification occurs, the refiner must notify EPA in writing no 
later than 20 days following the disqualifying event.
    The Act provides that the Secretary of Energy must conduct a study 
for EPA to determine whether compliance with the renewable fuels 
requirement would impose a disproportionate economic hardship on small 
refineries. If the study finds that compliance with the renewable fuels 
requirements would impose a disproportionate economic hardship on a 
particular small refinery, EPA is required to extend the small 
refinery's exemption for a period of not less than two additional years 
(i.e., to 2013). The Act also provides that a refiner with a small 
refinery may at any time petition EPA for an extension of the exemption 
for the reason of disproportionate economic hardship. In accordance 
with these provisions of the Act, we are finalizing the provision that 
refiners with small refineries may petition EPA for an extension of the 
small refinery exemption. As provided in the Act, EPA will act on the 
petition not later than 90 days after the date of receipt of the 
petition. Today's regulations do not provide a comparable opportunity 
for an extension of the small refinery exemption for small refiners. 
Therefore, all parties temporarily exempted from the RFS program on the 
basis of qualifying as a small refiner, rather than a small refinery, 
must comply with the program beginning January 1, 2011 (unless they 
waive their exemption prior to this date).
    During the initial exemption period for small refineries and small 
refiners and any extended exemption periods for small refineries, the 
gasoline produced by exempted small refineries and refineries owned by 
approved small refiners will not be subject to the renewable fuel 
standard.
    We proposed that the automatic exemption to 2011 and any small 
refinery extended exemptions may be waived upon notification to EPA; 
and we are finalizing this provision. Gasoline produced at a refinery 
which waives its exemption will be included in the RFS program and will 
be included in the gasoline used to determine the refiner's renewable 
fuel obligation. If a refiner waives the exemption for its small 
refinery or its exemption as a small refiner, the refiner will be able 
to separate and transfer RINs like any other obligated party. If a 
refiner does not waive the exemption, the refiner could still separate 
and transfer RINs, but only for the renewable fuel that the refiner 
itself blends into gasoline (i.e. the refinery operates as an oxygenate 
blender facility). Thus, exempt small refineries and small refiners who 
blend ethanol can separate RINs from batches without opting in to the 
program in the same manner that an oxygenate blender is allowed to do.
b. General Hardship Exemption
    In recent rulemakings, we have included a general hardship 
exemption for parties that are able to demonstrate severe economic 
hardship in complying with the standard. We proposed not to include 
provisions for a general hardship exemption in the RFS program. Unlike 
most other fuels programs, the RFS program includes inherent 
flexibility since compliance with the renewable fuels standard is based 
on a nationwide trading program, without any per gallon requirements, 
and without any requirement that the refiner or importer produce the 
renewable fuel. By purchasing RINs, obligated parties will be able to 
fulfill their renewable fuel obligation without having to make capital 
investments that may otherwise be necessary in order to blend renewable 
fuels into gasoline. We believe that sufficient RINs will be available 
and at reasonable prices, given that EIA projects that far greater 
renewable fuels will be used than required. Given the flexibility 
provided in the RIN trading program, including the provisions for 
deficit carry-over, and the fact that the standard is proportional to 
the volume of gasoline actually produced or imported, we continue to 
believe a general hardship exemption is not warranted. As a result, the 
final rule does not contain provisions for a general hardship 
exemption.
c. Temporary Hardship Exemption Based on Unforeseen Circumstances
    In recent rulemakings, we have included a temporary hardship 
exemption based on unforeseen circumstances. We proposed not to include 
such an exemption in the RFS program. The need for such an exemption 
would primarily be based on the inability to comply with the renewable 
fuels standard due to a natural disaster, such as a hurricane. However, 
in the event of a natural disaster, we believe it is likely that the 
volume of gasoline produced by an obligated party would also drop, 
which would result in a reduction in the renewable fuel requirement. 
We, therefore, reasoned in the NPRM that unforeseen circumstances, such 
as a hurricane or other natural disaster, would not result in a party's 
inability to obtain sufficient RINs to comply with the applicable 
renewable fuels standard.
    We received several comments regarding the inclusion of a temporary 
hardship exemption based on unforeseen circumstances. One commenter 
believes it would be of value to have a mechanism for selectively 
waiving or modifying the RFS downward on a temporary basis in the event 
of unforeseen circumstances such as significant drought affecting 
potential crop production. The commenter believes that crop shortages 
could have an impact on a national level, or a major disaster may 
impact logistics of renewable fuel distribution regionally, 
necessitating a more rapid response from EPA than is provided in the 
Energy Act. Another commenter believes that a temporary hardship 
exemption based on unforeseen circumstances should be included in the 
rule since it is impossible to predict how the RFS program will impact 
small refiners. Another commenter believes that, given the variety of 
potentially challenging unforeseen events during the last several 
years, it is not inconceivable that man-made or natural circumstances 
could adversely impact the RFS program. A natural disaster in the 
agricultural section, for example, may make it difficult to meet the 
renewable fuels mandate which, in turn, could drive the price of RINs 
high enough to disrupt the gasoline market. The commenter believes that 
a mechanism built into the program from the outset would provide a more 
flexible and less disruptive way to address unforeseen circumstances 
than the more time-consuming waiver process provided in the Energy Act.
    Under other EPA fuels programs, compliance is based on a 
demonstration that the fuel meets certain component or emissions 
standards. Unforeseen circumstances, such as a natural disaster, may 
affect an individual refiner's or importer's ability to produce or 
import fuel that complies with the

[[Page 23927]]

standards. As a result, we have included in other fuels programs 
provisions for a temporary hardship exemption from the standards in the 
event of an unforeseen natural disaster that affects a party's ability 
to produce gasoline that complies with the standards. Unlike most other 
fuels programs, compliance under the RFS program is based on a 
demonstration that a party has fulfilled its individual renewable fuels 
obligation on an annual basis, as compared to meeting specific gasoline 
content requirements. The renewable fuels obligation can be met through 
the use of purchased RINs, and there is a deficit carry forward 
provision allowing compliance to be shown over more than one year. In 
the event of a natural disaster, the volume of gasoline produced by an 
obligated party is also likely to drop, which would result in a 
reduction in the party's renewable fuel obligation. As a result, we 
believe that an individual party would be able to meet its renewable 
fuel obligation even in the event of a natural disaster that affects 
the party's refinery or blending facility. Therefore, unlike other 
fuels programs, we do not believe there is a need to include a 
temporary hardship exemption in the RFS rule to address an individual 
party's inability to comply with its renewable fuels obligation due to 
unforeseen circumstances.
    Most of the concerns raised by the commenters relate to problems 
that would have a more regional or national effect, as compared to 
affecting one or a few individuals. In the event that unforeseen 
circumstances do occur which result in a shortage of renewable fuel and 
available RINs, we believe that Congress provided an adequate mechanism 
for addressing such situations in the Energy Act.\29\ The Energy Act 
provides that on petition by one or more States, EPA, in consultation 
with the Departments of Agriculture and Energy, may waive the required 
aggregate renewable fuels volume obligation in whole or in part upon a 
sufficient showing of economic or environmental harm, or inadequate 
supply. As a result, we believe that a renewable fuel supply problem 
that affects all parties can be addressed using this statutory 
provision. We have carefully considered the comments; however, we do 
not believe that the comments provide a compelling rationale for 
providing a temporary hardship exemption from the RFS obligation based 
on unusual circumstances that goes beyond the provisions that Congress 
included in the Energy Act. As a result, the final rule does not 
contain provisions for a temporary hardship exemption based on 
unforeseen circumstances.
---------------------------------------------------------------------------

    \29\ CAA section 211(o)(7), as added by Section 1501(a) of the 
Energy Policy Act of 2005.
---------------------------------------------------------------------------

4. What Are the Opt-in and State Waiver Provisions Under the RFS 
Program?
a. Opt-in Provisions for Noncontiguous States and Territories
    The Act provides that, upon the petition of a noncontiguous state 
or U.S. territory, EPA may apply the renewable fuels requirements to 
gasoline produced in or imported into that noncontiguous state or U.S. 
territory at the same time as, or any time after the promulgation of 
regulations establishing the RFS program.\30\ In granting such a 
petition, EPA may issue or revise the RFS regulations, establish 
applicable volume percentages, provide for generation of credits, and 
take other actions as necessary to allow for the application of the RFS 
program in a noncontiguous state or territory. We believe that approval 
of the petition does not require a showing other than a request by the 
Governor of the State or the equivalent official of a Territory to be 
included in the program.
---------------------------------------------------------------------------

    \30\ CAA Section 211(o)(2)(A)(ii), as added by Section 1501(a) 
of the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Today's final rule will implement this provision of the Act by 
providing a process whereby the governor of a noncontiguous state or 
territory may petition EPA to have the state or territory included in 
the RFS program. The petition must be received by EPA on or before 
November 1 for the noncontiguous state or territory to be included in 
the RFS program in the next calendar year. A noncontiguous state or 
territory for which a petition is received after November 1 would not 
be included in the RFS program in the next calendar year, but would be 
included in the RFS program in the subsequent year. For example, if EPA 
receives a petition on September 1, 2007, the noncontiguous state or 
territory would be included in the RFS program beginning on January 1, 
2008. If EPA receives a petition on December 1, 2007, the noncontiguous 
state or territory would be included in the RFS program beginning 
January 1, 2009. We believe that requiring petitions to be received by 
November 1 is necessary to allow EPA time to make any adjustments in 
the applicable standard. The method for calculating the renewable fuels 
standard to reflect the addition of a state or territory that has opted 
into the RFS program is discussed in Section III.A. Because today's 
regulations make EPA approval of an opt-in petition automatic if it is 
signed by the appropriate authority and properly delivered to EPA, EPA 
does not envision providing an opportunity to comment on an opt-in 
request, although we will provide notice in the publication of the 
standard for the following year.
    We received several comments regarding when a noncontiguous state 
or territory should be able to opt-in to the RFS program. One commenter 
supported the approach in this final rule that EPA use the EIA Short-
term Energy Outlook published each October to assist in determining the 
percentage standard and therefore a state can only opt-in beginning 
with the first full compliance period of 2008. Another commenter 
believed we should include a provision to allow noncontiguous states or 
territories to opt-in to the first compliance period which starts 
September 1, 2007. While we see the merits of allowing a noncontiguous 
state or territory to opt-in to the first compliance period, we intend 
to maintain the current approach and allow noncontiguous states and 
territories to opt-in beginning with the 2008 compliance year. The 
statute clearly states that the program may apply to noncontiguous 
states and territories (that have petitioned EPA) at any time after 
these regulations have been promulgated. Given the short period of time 
between publication of the final rule and the effective date of the 
program, the need for a state and regulated parties to discuss opting-
in with knowledge of the final version of the rule, and the requirement 
for EPA to notify obligated parties with sufficient lead time to any 
change in the standard, EPA believes 2008 is the earliest practical 
date for an opt-in to be effective. In addition, EPA notes that none of 
the noncontiguous states or territories indicated a strong interest in 
opting-in for the remainder of the 2007 compliance period.
    Where a noncontiguous state or territory opts-in to the RFS 
program, producers and importers of gasoline for that state or 
territory will be obligated parties subject to the renewable fuel 
requirements. All refiners and importers who produce or import gasoline 
for use in a state or territory that has opted-in to the RFS program 
will be required to comply with the renewable fuel standard and will be 
able to separate RINs from batches of renewable fuels in the same 
manner as other obligated parties.
    Once a petition to opt-in to the RFS program is approved by EPA, 
the state or territory would remain in the RFS program and be treated 
as any of the 48 contiguous states. We received a comment asserting 
that once a state or

[[Page 23928]]

territory opts-in, they should be required to remain in the program for 
at least 5 years. As stated earlier, EPA will recognize a state or 
territory that opts-in to the program as identical to any of the 48 
states. The current regulations do not allow a state to opt-out and the 
only form of relief from the program is a waiver, in whole or in part, 
of the national renewable fuel volume requirement. Noncontiguous states 
and territories should be aware of the obligations of the program and 
should only choose to opt-in if they expect to meet those obligations 
for the indefinite future. If in the future a state believes EPA should 
change its regulations and allow an opt-out the state could petition 
EPA to change the regulations. As in other situations where a party 
petitions EPA to revise its regulations, EPA would be in a position at 
that point to consider the concerns raised by the state as well as 
other interested stakeholder and to determine whether it would be 
appropriate to revise the regulations.
b. State Waiver Provisions
    The Energy Act provides that EPA, in consultation with the U.S. 
Department of Agriculture (USDA) and the Department of Energy (DOE), 
may waive the renewable fuels requirements in whole or in part upon a 
petition by one or more states by reducing the national quantity of 
renewable fuel required under the Act.\31\ The Act also outlines the 
basic requirements for such a waiver, such as a demonstration that 
implementation of the renewable fuels requirements would severely harm 
the economy or environment of a state, a region, or the United States 
or that there is an inadequate domestic supply of renewable fuel.
---------------------------------------------------------------------------

    \31\ CAA Section 211(o)(7), as added by Section 1501(a) of the 
Energy Policy Act of 2005.
---------------------------------------------------------------------------

    If EPA, after public notice and opportunity for comment, approves a 
state's petition for a waiver of the RFS program, the Act stipulates 
that the national quantity of renewable fuel required (Table I.B-1) may 
be reduced in whole or in part. This reduction could reduce the 
percentage standard applicable to all obligated parties. However, there 
is no provision in the Act that would permit EPA to reduce or eliminate 
any obligations under the RFS program specifically for parties located 
within the state that petitioned for the waiver. Thus all refiners, 
importers, and blenders located in the state would still be obligated 
parties if they produce gasoline. In addition, an approval of a state's 
petition for a waiver may not have any impact on renewable fuel use in 
that state since it would not be a prohibition on the sale or 
consumption of renewable fuels in that state. In fact, the Act 
prohibits the regulations from restricting the geographic areas in 
which renewable fuels may be used.\32\ Renewable fuel use in the state 
in question would thus continue to be driven by natural market forces 
and, perhaps if the economics of ethanol blending were less favorable 
than today, the nationally-applicable renewable fuel standard.
---------------------------------------------------------------------------

    \32\ CAA Section 211(o)(2)(iii), as added by Section 1501(a) of 
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Given that state petitions for a waiver of the RFS program appear 
unlikely to affect renewable fuel use in that state, we have not 
finalized regulations providing more specificity regarding the criteria 
for a waiver or the ramifications of Agency approval of such a waiver 
in terms of the level or applicability of the standard. However, states 
can still submit petitions to the Agency for a waiver of the RFS 
requirements under the provision in the Energy Act and such petitions 
will be addressed by EPA on a case-by-case basis.
    We received several comments objecting to the decision to not 
propose regulations detailing the waiver process and our rationale for 
not doing so. One commenter stated that nothing in the statute prevents 
relief from being directed toward a state which has requested the 
waiver by reducing the renewable fuel obligation of refiners, blenders, 
and importers who market gasoline in the affected state. Contrary to 
the commenter's assertion, the statute states that, ``[t]he 
Administrator * * * may waive the requirements * * * by reducing the 
national quantity of renewable fuel required''.\33\ Congress's clear 
intent was to limit EPA's authority to provide relief under the state 
waiver provision of section 211(o)(7). Relief under that provision is 
limited to reducing the total national volume required under the RFS 
program. Thus, the renewable volume obligation for regulated parties 
would be reduced, but the reduced obligation would still apply to all 
obligated refiners, blenders and importers, including those in the 
state that requested the waiver. This may provide some relief to the 
part of the country submitting the petition, but EPA is not authorized 
to grant other more targeted relief such as reducing the percentage for 
some refiners and not others or refusing to count towards compliance 
renewable fuel that is produced or used in certain parts of the 
country. It should be noted here that this approach holds true for 
states or territories which have opted-in to the program as well. Once 
a state or territory has opted-in to the program, they will be treated 
as identical to any other state and specific relief will not be 
provided to regulated parties serving these areas after the approval of 
a waiver. Noncontiguous states and territories should consider this in 
discussions with regulated parties before opting-in to the program.
---------------------------------------------------------------------------

    \33\ CAA Section 211(o)(7), as added by Section 1501(a) of the 
Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Another commenter stated that EPA should publish regulations 
outlining specific criteria that will be considered in reviewing a 
petition, so that the public would have a more meaningful opportunity 
to participate in the process. While EPA realizes that the criteria 
provided by the statute are quite general, the rationales of severe 
environmental or economic harm or inadequate domestic supply are 
sufficient for a basic framework upon which a petition can be built and 
evaluated. Each situation in which a waiver may be requested will be 
unique, and promulgating a list of more specific criteria in the 
abstract may be counter-productive. Communication between the 
petitioning state(s), EPA, DOE, USDA, and public and industry 
stakeholders should begin early in the process, well before a waiver 
request is submitted. This communication will supply these federal 
agencies with a knowledgeable background of the situation prompting the 
potential waiver request. The waiver request may even prove unnecessary 
after an initial investigation and analysis of the situation. If not, 
and if the state continues to believe that a valid basis for submission 
of a petition exists, federal agencies can instruct the state(s) as to 
what more detailed information is needed for waiver approval. Petitions 
will be published in the Federal Register, as required by statute, to 
provide public notice and opportunity for comment.
    A third commenter raised the point that there is no provision in 
the Act that would permit EPA to waive any obligations for specific 
entities in a state that has petitioned for a waiver, and in the case 
of an emergency, such as a natural disaster, specific relief may be 
warranted. The commenter is correct in the observation that EPA cannot 
waive obligations for specific entities or locations. However, the Act 
does authorize EPA to waive the obligations of the program as it 
applies to all obligated parties, in whole or in part, depending on the 
severity of the situation.

[[Page 23929]]

D. How Do Obligated Parties Comply With the Standard?

    Under the Act, EPA is to establish a renewable fuel standard 
annually, expressed as a percentage of gasoline sold or introduced into 
commerce, that will ensure that overall a specified total national 
volume of renewable fuels will be used in gasoline in the U.S. The Act 
does not require each obligated party to necessarily do the blending 
themselves in order to comply with this obligation. Rather, under the 
credit trading program required by the Act, each obligated party is 
allowed to satisfy its obligations either through its own actions or 
through the transfer of credits from others who have more than 
satisfied their individual requirements.
    This section describes our final compliance program. It is based on 
the use of unique renewable identification numbers (RINs) assigned to 
batches of renewable fuel by renewable fuel producers and importers. 
These RINs can then be sold or traded, and ultimately used by any 
obligated party to demonstrate compliance with the applicable standard. 
Excess RINs serve the function of the credits envisioned by the Act and 
also provide additional benefits, as described below. We believe that 
our approach is consistent with the language and intent of the Act and 
preserves the natural market forces and blending practices that will 
keep renewable fuel costs to a minimum.
1. Why Use Renewable Identification Numbers?
    Once renewable fuels are produced or imported, there is very high 
confidence that all but de minimus quantities will in fact be blended 
into gasoline or otherwise used as motor vehicle fuels, except for 
exports. Renewable fuels are not used for food, chemicals, or as 
feedstocks to other production processes. In fact the denaturant that 
must be added to ethanol is designed specifically to ensure that the 
ethanol is primarily used as motor vehicle fuel. In discussions with 
stakeholders prior to release of the NPRM, it became clear that other 
renewable fuels, including biodiesel and renewable fuels used in their 
neat (unblended) form, likewise are not used in appreciable quantities 
for anything other than motor vehicle fuel. Therefore if a refiner 
ensures that a certain volume of renewable fuel has been produced, in 
effect they have also ensured that this volume will be blended into 
gasoline or otherwise used as a motor vehicle fuel. Focusing on 
production of renewable fuel as a surrogate for use of such fuel has 
many benefits as far as streamlining the program and minimizing the 
influence that the program has on the operation of the market.
    In order to implement a program that is based on production of a 
certain volume of renewable fuels, we are finalizing a system of volume 
accounting and tracking of renewable fuels. We are requiring that this 
system be based on the assignment of unique numbers to each batch of 
renewable fuel. These numbers are called Renewable Identification 
Numbers or RINs, and are assigned to each batch by the renewable fuel 
producer or importer.
    The use of RINs allows the Agency to measure and track renewable 
fuel volumes starting at the point of their production rather than at 
the point when they are blended into conventional fuels. Although an 
alternative approach would be to measure renewable fuel volumes as they 
are blended into conventional gasoline or diesel, measuring renewable 
fuel volumes at the point of production provides more accurate 
measurements that can be easily verified. For instance, ethanol 
producers are already required to report their production volumes to 
EIA through Monthly Oxygenate Reports. These data provide an 
independent source for verifying volumes. The total number of batches 
and parties involved are also minimized in this approach. The total 
number of batches is smallest at the point of production, since batches 
are commonly split into smaller ones as they proceed through the 
distribution system to the place where they are blended into 
conventional fuel. The number of renewable fuel producers is also far 
smaller than the number of blenders. Currently there just over 100 
ethanol plants and 85 biodiesel plants in the U.S., compared with 
approximately 1200 blenders \34\ based on IRS data.
---------------------------------------------------------------------------

    \34\ Those blenders who add ethanol to RBOB are already 
regulated under our reformulated gasoline regulations.
---------------------------------------------------------------------------

    The assignment of RINs to batches of renewable fuel at the point of 
their production also allows those batches to be identified according 
to various categories important for compliance purposes. For instance, 
the RIN will contain a component that specifies whether a batch of 
ethanol was made from cellulosic feedstocks. This RIN component will be 
of particular importance for 2013 and beyond when the Act specifies a 
national volume requirement for cellulosic biomass ethanol. The RIN 
will also identify the Equivalence Value of the renewable fuel which 
will often only be known at the point of its production. Finally, the 
RIN will identify the year in which the batch was produced, a critical 
element in determining the applicable time period within which RINs are 
valid for compliance purposes.
    Although production volumes of renewable fuels intended for 
blending into gasoline are a reasonably accurate surrogate for volumes 
ultimately blended into gasoline, changes can occur at various times 
throughout the year in the volumes of renewable fuel that are in 
storage. These stock changes involve the temporary storage of renewable 
fuel during times of excess and can affect the length of time between 
production and ultimate use. While there may be seasonal fluctuations 
in stocks due to seasonal demand, these stock changes always have a net 
change of zero over the long term since there is no economic benefit to 
stockpiling renewable fuels. As a result there is no need to account 
for stock changes in our program.
    Exports of renewable fuel represent the only significant 
distribution pathway that could impair the use of production as a 
surrogate for renewable fuel blending into gasoline or other use as a 
motor vehicle fuel. However, our approach accounts for exports through 
an explicit requirement placed upon exporters (discussed in Section 
III.D.4 below). As a result, we are confident that our approach 
satisfies the statutory obligation that our regulations impose 
obligations on refiners and importers that will ensure that gasoline 
sold or introduced into commerce in the U.S. each year will contain the 
volumes of renewable fuel specified in the Act. By tracking the amount 
of renewable fuel produced or imported and subtracting the amount 
exported, we will have an accurate accounting of the renewable fuel 
actually consumed as motor vehicle fuel in the U.S. Exports of 
renewable fuel are discussed in more detail in Section III.D.4.
a. RINs Serve the Purpose of a Credit Trading Program
    According to the Act, we must promulgate regulations that include 
provisions for a credit trading program. The credit trading program 
allows a refiner that overcomplied with its annual RVO to generate 
credits representing the excess renewable fuel. The Act stipulates that 
those credits can then be used within the ensuing 12 month period, or 
transferred to another refiner that had not blended sufficient 
renewable fuel into its gasoline to satisfy its RVO. In this way the 
credit trading program permits current blending practices to continue 
wherein

[[Page 23930]]

some refiners purchase a significant amount of renewable fuel for 
blending into their gasoline while others do little or none, thus 
providing a means for all refiners to economically comply with the 
standard.
    Our RIN-based program fulfills all the functions of a credit 
trading program and thus meets the Act's requirements. If at the end of 
a compliance period a party had more RINs than it needed to show 
compliance with its renewable volume obligation, these excess RINs 
would serve the function of credits and could be used or traded in the 
next compliance period. RINs can be transferred to another party in an 
identical fashion to a credit. However, our program provides additional 
flexibility in that it permits all RINs to be transferred between 
parties before they are deemed to be in excess of a party's annual RVO 
at the end of the year. This is because a RIN serves two functions: It 
is direct evidence of compliance and, after a compliance year is over, 
excess RINs serve the function of credits for overcompliance. Thus the 
RIN approach has the advantage of allowing real-time trading without 
having to wait until the end of the year to determine excess.
    As in other motor vehicle fuels credit programs, we are also 
requiring that any renewable producer that generates RINs must use an 
independent auditor to conduct annual reviews of the party's renewable 
production, RIN generation, and RIN transactions. These reviews are 
called ``attest engagements,'' because the auditor is asked to attest 
to the validity of the regulated party's credit transactions. For 
example, the reformulated gasoline program requires attest engagements 
for refiners and importers, and downstream oxygenate blenders to verify 
the underlying documentation forming the basis of the required reports 
(40 CFR part 80, subpart F). In the case of RIN generation, the auditor 
is required to verify that the number of RINs generated matched the 
volume of renewable fuels produced, that any extra value RINs are 
appropriately generated, and that RIN numbers are properly transferred 
with the renewable fuel as required by the regulations.
b. Alternative Approach to Tracking Batches
    If we had not implemented a RIN-based system for uniquely 
identifying, measuring, and tracking batches of renewable fuel, the RFS 
program would necessarily require that we measure renewable fuel 
volumes at the point in the distribution system where they are actually 
blended into conventional gasoline or diesel or used in their neat form 
as motor vehicle fuel. The NPRM described a number of significant 
problems that this approach would create, including the potential for 
double-counting, increasing the number of parties subject to 
enforcement provisions, and the loss of a distinction between 
cellulosic ethanol and other forms of ethanol. We concluded that a 
blender-based approach to tracking volumes of renewable fuel was 
inferior to our proposed program focusing on the point of production 
and importation. We did not receive any comments supporting a blender-
based approach and, consistent with the rationale provided in the 
proposed rule, have decided not to implement it.
2. Generating RINs and Assigning Them to Batches
a. Form of Renewable Identification Numbers
    Each RIN is generated by the producer or importer of the renewable 
fuel and uniquely identifies not only a specific batch, but also every 
gallon in that batch. The RIN consists of a 38-character code having 
the following form:

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 cellulosic biomass ethanol.
SSSSSSSS = Start of RIN block.
EEEEEEEE = End of RIN block.

    In response to the NPRM, one commenter requested that the full RIN 
generation date, not just the year, be included in the RIN. We believe 
that this is unnecessary and would unduly lengthen the RIN. Compliance 
with the standard is determined on a calendar year basis, and the year 
of RIN generation is necessary in order to ensure that RINs are used 
for compliance purposes only in the calendar year generated or the 
following year. See Section III.D.3.b. The full RIN generation date, 
while a potentially useful piece of information in the context of 
potential enforcement activities, is not necessary as a component of 
the RIN since recordkeeping requirements contain this same information 
and can be consulted in the enforcement context.
    The company and facility IDs are assigned by the EPA as part of the 
registration process as described in Section IV.B. Company IDs will be 
used primarily to determine compliance, while the inclusion of facility 
IDs allows the assignment of batch numbers unique to each facility. The 
use of both company and facility IDs is also consistent with our 
approach in other fuel programs. The batch number is chosen by the 
producer and includes five digits to allow for facilities that produce 
up to a hundred thousand batches per year. In the NPRM we proposed that 
batch numbers be sequential values starting with 00001 at the beginning 
of each year. Following release of the NPRM, some stakeholders 
expressed the desire to be able to align RIN batch numbers with numbers 
used in other aspects of their business. As a result, we have 
determined that the requirement that the batch numbers be sequential is 
not necessary so long as each batch number is unique within a given 
calendar year. Batches are described more fully in Section III.E.1.a.
    The RR, D, and K codes together describe the nature of the 
renewable fuel and the RINs that are generated to represent it. The RR 
code simply represents the Equivalence Value for the renewable fuel, 
multiplied by 10 to eliminate the decimal place inherent in Equivalence 
Values. Equivalence Values form the basis for the total number of RINs 
that can be generated for a given volume of renewable fuel, and are 
described in Section III.B.4.
    The D code identifies cellulosic biomass ethanol batches as such. 
Since the Act requires that a minimum of 250 million gallons of 
cellulosic biomass ethanol be consumed starting in 2013, obligated 
parties will need to be able to distinguish RINs representing 
cellulosic biomass ethanol from RINs representing other types of 
renewable fuel. This requirement is discussed in more detail in Section 
III.A.
    In the NPRM, the K code served to distinguish between standard-
value RINs and extra-value RINs, and it was placed in the middle of the 
RIN. As described more fully in Section III.E.1.a, our final rule 
eliminates the need for a distinction between standard-value RINs and 
extra-value RINs, but requires a distinction between RINs that must be 
transferred with a volume of renewable fuel (assigned RINs) and RINs 
that can be transferred without renewable fuel (separated RINs). Thus 
for the final rule we have changed the purpose of the K code. As 
described in Section III.E.2, we are requiring that RINs separated from 
volumes of renewable fuel be identified as such, by changing the K code 
from a value of 1 to a value of 2. Placing the K code at the beginning 
of the RIN

[[Page 23931]]

makes this process more straightforward for obligated parties and 
oxygenate blenders who will be responsible for changing the K code 
after separating a RIN from renewable fuel.
    The RIN also contains two codes SSSSSSSS and EEEEEEEE that together 
identify the ``RIN block'' which demarcates the number of gallons of 
renewable fuel that the batch represents in the context of compliance. 
Depending on the Equivalence Value, this may not necessarily be the 
same as the actual number of gallons in the batch. The methodology for 
designating the SSSSSSSS and EEEEEEEE values is described in Section 
III.D.2.b below.
    In the NPRM we assigned six digits to the RIN block codes to allow 
batches up to a million gallons in size. Based on comments received, we 
have decided to expand the number of digits to eight to accommodate 
batches up to 100 million gallons in size. Although it is highly 
unlikely that a single tank would hold this volume, we are adding a 
definition of ``batch'' to our final regulations that would allow this 
high volume to be counted as a single batch for the purposes of 
generating RINs.
    In the NPRM we pointed out that ``RIN'' can refer to either the 
number representing an entire batch or the number representing one 
gallon of renewable fuel in the context of compliance. In order to make 
the distinction clear, we are defining the latter as a gallon-RIN, and 
a batch-RIN will represent multiple gallon-RINs. In the case of a 
gallon-RIN, the values of SSSSSSSS and EEEEEEEE will be identical. A 
batch-RIN, on the other hand, will generally have different values for 
SSSSSSSS and EEEEEEEE, representing the starting and ending values of a 
batch of renewable fuel. Examples of RINs are presented in the next 
section.
b. Generating RINs
    As described in Section III.E.1.a, we have eliminated the 
distinction between standard-value RINs and extra-value RINs for this 
final rule. Instead, all gallon-RINs must be assigned to batches of 
renewable fuel by the producer or importer. Consistent with the NPRM, 
each gallon-RIN will continue to represent one gallon of renewable fuel 
in the context of compliance.
    Also consistent with the NPRM, we are requiring that RIN generation 
begin at the same time that the renewable fuel standard becomes 
applicable to obligated parties. Thus RINs must be generated for all 
renewable fuel produced or imported on or after September 1, 2007. 
Since many producers and importers will have renewable fuel in 
inventory at the start of the program that was produced prior to 
September 1, 2007, we are also allowing them to generate RINs for such 
renewable fuel. This provision ensures that every gallon that a 
producer or importer sells starting on September 1, 2007 can have an 
assigned RIN, and obligated parties that take ownership of renewable 
fuel directly from a producer or importer will have greater assurance 
of having access to RINs at the start of the program. Other volumes of 
ethanol in inventory in the distribution system on September 1, 2007 
will continue to be sold and distributed without RINs.
    In order to determine the number of gallon-RINs that must be 
generated and assigned to a batch by a producer or importer, the actual 
volume of the batch must be multiplied by the Equivalence Value to 
determine an applicable ``RIN volume'':

VRIN = EV x Vs

Where:

VRIN = RIN volume, in gallons, representing the number of 
gallon-RINs that must be generated (rounded to the nearest whole 
gallon).
EV = Equivalence value for the renewable fuel.
Vs = Standardized volume of the batch of renewable fuel 
at 60 [deg]F, in gallons.

    When RINs are first assigned to a batch of renewable fuel by its 
producer or importer, the RIN block start for that batch will in 
general be 1 (i.e., SSSSSSSS will have a value of 00000001). The RIN 
block end value EEEEEEEE will be equal to the RIN volume calculated 
above. The batch-RIN then represents all the gallon-RINs assigned to 
the batch. Table III.D.2.b-1 provides some examples of the number of 
gallon-RINs that would be assigned to a batch under different 
circumstances.

              Table III.D.2.B-1.--Examples of Batch-RINs 35
------------------------------------------------------------------------

-------------------------------------------------------------------------
Batch volume: 2000 gallons corn ethanol.
Equivalence value: 1.0.
Gallon-RINs: 2000.
Batch-RIN: 1-2007-1234-12345-00001-10-2-00000001-00002000.
------------------------------------------------------------------------
Batch volume: 2000 gallons biodiesel.
Equivalence value: 1.5.
Gallon-RINs: 3000.
Batch-RIN: 1-2007-1234-12345-00002-15-2-00000001-00003000.
------------------------------------------------------------------------
Batch volume: 2000 gallons cellulosic ethanol.
Equivalence value: 2.5.
Gallon-RINs: 5000.
Batch-RIN: 1-2007-1234-12345-00003-25-1-00000001-00005000.
------------------------------------------------------------------------

    The RIN block will often represent the actual number of gallons in 
the batch, for cases where the Equivalence Value is 1.0. In other 
cases, the RIN block start and RIN block end values in the batch-RIN 
will not exactly correspond to the volume of the batch. For instance, 
in cases where the Equivalence Value is larger than 1.0, the number of 
gallon-RINs generated will be larger than the number of gallons in the 
batch. In such cases the batch will have a greater value in terms of 
compliance than a batch with the same volume but an Equivalence Value 
equal to 1.0. Likewise, a batch with an Equivalence Value less than 1.0 
will have a smaller value in terms of compliance than a batch with the 
same volume but an Equivalence Value equal to 1.0. In the context of 
our modified approach to RIN distribution as described in Section 
III.E.1, however, the transfer of RINs with batches will be 
straightforward regardless of the number of gallon-RINs assigned to a 
particular volume of renewable fuel, as every gallon-RIN will always 
have the capability of covering one gallon of an obligated party's RVO.
---------------------------------------------------------------------------

    \35\ RIN codes have been separated by hyphens in this table for 
demonstrative purposes only. In actual use, no hyphens would be 
present in the RIN.
---------------------------------------------------------------------------

    In response to the NPRM, some obligated parties requested that 
fractional RINs be used for cases in which the Equivalence Value is 
less than 1.0. Under this approach, every gallon in a batch would still 
have an assigned gallon-RIN, but those gallon-RINs would represent only 
a fraction of a gallon for compliance purposes. The commenters also 
argued that our proposed system in which RINs are assigned to only a 
portion of a batch would be unworkable given the need to ensure that 
RINs remain assigned to batches as they travel through the distribution 
system.
    We continue to believe that the most straightforward system 
calculates the number of gallon-RINs representing a batch as the 
product of the Equivalence Value and the actual volume of the batch. 
Then every gallon-RIN will have the capability of covering one gallon 
of an obligated party's RVO, and thus every gallon-RIN has the same 
value. This is true both for renewable fuels with Equivalence Values 
less than 1.0, and renewable fuels with Equivalence Values greater than 
1.0. Also, as described in Section III.E.1, we have modified our 
approach to the distribution of RINs assigned to volumes of renewable 
fuel. As a result, the batch-splitting and batch-merging protocols have 
become largely irrelevant, and thus the transfer of renewable fuels 
having an

[[Page 23932]]

Equivalence Value less than 1.0 has become greatly simplified. We are 
therefore finalizing our proposed approach in which renewable fuels 
having an Equivalence Value less than 1.0 result in fewer assigned 
gallon-RINs than gallons in a batch.
    Following release of the NPRM, we also identified some cases in 
which the generation of RINs for a partially renewable fuel or blending 
component would result in double-counting of RINs generated. For 
instance, ethyl tertiary butyl ether (ETBE) is made from combining 
ethanol with isobutylene. The ethanol is generally from corn, and the 
isobutylene is generally from petroleum. The ETBE producer may purchase 
ethanol from another source, and that ethanol may already have RINs 
assigned to it. In such cases it would not be appropriate for the ETBE 
producer to generate additional RINs for the ETBE made from that 
ethanol. Even if the ETBE producer purchased ethanol without assigned 
RINs, our program design ensures that either RINs were generated for 
the ethanol and separated prior to purchase by the ETBE producer, or 
RINs were legitimately not assigned to the ethanol. The NPRM did not 
address the potential for generating RINs twice for the same renewable 
fuel in these cases. Therefore, we are finalizing a provision 
prohibiting a party from generating RINs for a partially renewable fuel 
or blending component that it produces if the renewable feedstock used 
to make the renewable fuel or blending component was acquired from 
another party. Any RINs acquired with the renewable feedstock (e.g. 
ethanol) must be assigned to the product made from that feedstock (e.g. 
ETBE). This approach is consistent with comments submitted by Lyondell 
Chemical Company.
c. Cases in Which RINS Are Not Generated
    Although in general every batch of renewable fuel produced or 
imported must have an assigned batch-RIN, there are several cases in 
which a RIN may not be assigned to a batch by a producer or importer. 
For instance, if the renewable fuel was consumed within the confines of 
the production facility where it was made, it would not be acquired by 
either an obligated party or a gasoline blender. In such cases, the RIN 
could not be separated from the batch and transferred separately since 
producers do not have this right. A RIN is assigned to renewable fuel 
when ownership of the renewable fuel is transferred to another party. 
Since no such transfer would occur in this case, no RIN should be 
generated.
    A second case in which some renewable fuel would not have an 
assigned RIN would occur for small volume producers. We are allowing 
renewable fuel producers who produce less than 10,000 gallons in a year 
to avoid the requirement to generate RINs and assign them to batches. 
Such producers would not contribute meaningfully to the nationwide pool 
of renewable fuel, and we do not believe that the very small business 
operations involved should be subject to the burden of recordkeeping 
and reporting. Although two commenters disagreed that these small 
volume producers should be exempt from the requirement to generate 
RINs, they did not provide compelling evidence that the exemption would 
create a problem in the distribution system or provide an unfair 
advantage to small producers. As a result we are finalizing this 
provision as proposed. Note that if a small producer chooses to 
register as a renewable fuel producer under the RFS program, they will 
be subject to all the regulatory provisions that apply to all 
producers, including the requirement to assign RINs to batches.
    In the NPRM we proposed that a renewable fuel producer which also 
operated as an exporter would not be required to generate and assign a 
RIN to any renewable fuel that it produced and exported. However, one 
commenter pointed out that this approach could lead to confusion 
regarding which gallons should have an assigned RIN and which should 
not, given the complex nature of tracking volumes of renewable fuel. As 
a result we have determined that this provision should be eliminated. 
Our final regulations require that producers assign RINs to all 
renewable fuel, regardless of whether it is exported. Exports of 
renewable fuel are discussed further in Section III.D.4.
3. Calculating and Reporting Compliance
    Under our program, RINs form the basis of the volume accounting and 
tracking system that allows each obligated party to demonstrate that 
they have met their renewable fuel obligation each year. This section 
describes how the compliance process using RINs works. Our approach to 
the distribution and trading of RINs is covered separately in Section 
III.E below.
a. Using RINs To Meet the Standard
    Under our program, each obligated party must determine its 
Renewable Volume Obligation (RVO) based on the applicable percentage 
standard and its annual gasoline volume as described in Section 
III.A.4. The RVO represents the volume of renewable fuel that the 
obligated party must ensure is used in the U.S. in a given calendar 
year. Since the nationwide renewable fuel volumes shown in Table I.B-1 
are required by the Act to be consumed in whole calendar years, each 
obligated party must likewise calculate its RVO on an annual basis.
    Since our program uses RINs as a measure of the amount of renewable 
fuel used as motor vehicle fuel that is sold or introduced into 
commerce within the U.S., obligated parties must meet their RVO through 
the accumulation of RINs. In so doing, they will effectively be causing 
the renewable fuel represented by the RINs to be consumed as motor 
vehicle fuel. Obligated parties are not required to physically blend 
the renewable fuel into gasoline or diesel fuel themselves. The 
accumulation of RINs is the means through which each obligated party 
shows compliance with its RVO and thus with the renewable fuel 
standard.
    For each calendar year, each obligated party is required to submit 
a report to the Agency documenting the RINs it acquired and showing 
that the sum of all gallon-RINs acquired is equal to or greater than 
its RVO. This reporting is discussed in more detail in Section IV. In 
the context of demonstrating compliance, all gallon-RINs have the same 
compliance value. The Agency can then verify that the RINs used for 
compliance purposes are valid by simply comparing RINs reported by 
producers to RINs claimed by obligated parties. We can also verify 
simply that any given gallon-RIN was not double-counted, i.e., used by 
more than one obligated party for compliance purposes. In order to be 
able to identify the cause of any double-counting, however, additional 
information is needed on RIN transactions as discussed in Section IV.
    If an obligated party has acquired more RINs than it needs to meet 
its RVO, then in general it can retain the excess RINs for use in 
complying with its RVO in the following year or transfer the excess 
RINs to another party. The conditions under which this is allowed are 
determined by the valid life of a RIN, described in more detail in 
Section III.D.3.b below. If, alternatively, an obligated party has not 
acquired sufficient RINs to meet its RVO, then under certain conditions 
it can carry a deficit into the next year. Deficit carryovers are 
discussed in more detail in Section III.D.3.d.
    The regulations prohibit any party from creating or transferring 
invalid RINs. Invalid RINs cannot be used in demonstrating compliance 
regardless of

[[Page 23933]]

the good faith belief of a party that the RINs are valid. These 
enforcement provisions are necessary to ensure the RFS 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 refiner or importer that used the invalid RINs will be required to 
deduct any invalid RINs from its compliance calculations. The refiner 
or importer will be liable for violating the standard if the remaining 
number of valid RINs is insufficient to meet its RVO, and the obligated 
party may be subject to additional monetary penalties if it used 
invalid RINs in its compliance demonstration. See Section V of this 
preamble for further discussion regarding liability for use of invalid 
RINs.
    Just as for RIN generators, we are also requiring that obligated 
parties conduct attest engagements for the volume of gasoline they 
produce and the number of RINs procured to ensure compliance with their 
RVO. In most cases, this should amount to little more than is already 
required under existing EPA gasoline regulations. In the case of 
renewable fuel exporters, the attest engagement will verify the volume 
of renewable fuel exported and therefore the magnitude of their RVO. 
Attest engagement reports must be submitted to the party that 
commissioned the engagement and to EPA. See Section IV of this preamble 
for further discussion of the attest engagement requirements.
b. Valid Life of RINs
    The Act requires that renewable fuel credits be valid for showing 
compliance for 12 months as of the date of generation. This section 
describes our interpretation of this provision in the context of our 
program wherein excess RINs fulfill the Act's requirements regarding 
credits.
    As discussed in Section III.D.1.a, we interpret the Act 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 will determine compliance shortly after the end of the year, 
and credits would be identified at that time. Obligated parties will 
typically demonstrate compliance by submitting a compliance 
demonstration to EPA. Given the 12-month life of a credit as stated in 
the Act, we interpret this provision as meaning that credits would only 
be valid for compliance purposes for the following compliance year. 
Hence if a refiner or importer overcomplied with their 2007 obligation 
they would generate credits that could be used to show compliance with 
the 2008 compliance obligation, but the credits could not be used to 
show compliance for later years. Since RINs fulfill the role of 
credits, the statutory provisions regarding credits apply to RINs
    The Act's limit on credit life helps balance the risks between the 
needs of renewable fuel producers and obligated parties. Producers are 
currently making investments in expanded production capacity on the 
expectation of a statutorily guaranteed minimum quantity demanded. 
Under the market conditions we are experiencing today that make ethanol 
use more economically attractive, the annual volume requirements in the 
RFS program will not drive consumption of renewable fuels. However, if 
the price of crude oil dropped significantly or the use of ethanol in 
gasoline became otherwise less economically attractive, obligated 
parties could use stockpiled credits to comply with the program 
requirements. As a result, demand for renewable fuel could fall well 
below the RFS program requirements, and many producers could end up 
with a stranded investment. The 12 month valid life limit for credits 
minimizes the potential for this type of result.
    For obligated parties, the Act's 12 month valid life for credits 
provides a window within which parties who do not meet their renewable 
fuel obligation through their own physical use of renewable fuel can 
obtain credits from other parties who have excess. This critical aspect 
of the trading system allows the renewable fuels market to continue 
operating according to natural market forces, avoiding the possibility 
that every single refiner would need to purchase renewable fuel for 
blending into its own gasoline. But the 12 month life also provides a 
window within which banking and trading can be used to offset the 
negative effects of fluctuations in either supply of or demand for 
renewable fuels. For instance, if crude oil prices were to drop 
significantly and natural market demand for ethanol likewise fell, the 
RFS program would normally bring demand back up to the minimum required 
volumes shown in Table I.B-1. But in this circumstance, the use of 
ethanol in gasoline would be less economically attractive, since demand 
for ethanol would not be following price but rather the statutorily 
required minimum volumes. As a result, the price of credits as 
represented by RINs, and thus ethanol blends, could rise above the 
levels that would exist if no minimum required volumes existed. The 12 
month valid life creates some flexibility in the market to help 
mitigate price fluctuations. The renewable fuels market could also 
experience a significant drop in supply if, for instance, a drought 
were to limit the production of the feedstocks needed to produce 
renewable fuel. Obligated parties could use banked credits to comply 
rather than carry a deficit into the next year.
    In the context of our RIN-based program, we have been able to 
accomplish the same objective as the Act's 12 month life of credits 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 an obligated party needed in that year, making excess RINs 
equivalent to the credits referred to in the Energy Act. Excess RINs 
are valid for compliance purposes in the year following the one in 
which they initially came into existence.\36\ RINs not used within 
their valid life will expire. This approach satisfies the Act's 12 
month duration for credits.
---------------------------------------------------------------------------

    \36\ The use of previous-year RINs for current year compliance 
purposes will also be limited by the 20 percent RIN rollover cap 
under today's final rule. However, as discussed in the next section, 
we believe that this cap will still provide a significant amount of 
flexibility to obligated parties.
---------------------------------------------------------------------------

    Thus we are requiring that every RIN be valid for the calendar-year 
compliance period in which it was generated or the following year. If a 
RIN was created in one year but was not used by an obligated party to 
meet its RVO for that year, the RIN can be used for compliance purposes 
in the next year (subject to certain provisions to address RIN rollover 
as discussed below). If, however, a RIN was created in one year and was 
not used for compliance purposes in that year or in the next year, it 
will expire. In response to the NPRM, this approach was supported by a 
number of obligated parties and their representative associations. 
These commenters agreed that allowing RINs to be used for the year 
generated or the following year was not only supported by the statutory 
language, but was also an element of program flexibility that would be 
critical for offsetting the negative effects of potential fluctuations 
in either supply of or demand for renewable fuels.

[[Page 23934]]

    However, in response to our NPRM, other commenters said that the 
Energy Act's 12-month credit life provision should be interpreted as 
applying retrospectively, not prospectively. Under this approach, the 
12-month timeframe in the Act would be interpreted to refer to the full 
calendar year within which a credit was generated. Under this 
alternative approach no RINs could be used for compliance purposes 
beyond the calendar year in which they originally came into existence. 
As discussed below, we do not believe that this approach is 
appropriate.
    Commenters who supported the retrospective approach to the Act's 
12-month credit life provision argued that the Energy Act could have 
been written to explicitly allow a valid life of multiple years if that 
had been Congress' intent. In response, the Act explicitly indicates 
that obligated parties may either use the credits they have generated 
or transfer them. For a party to be able to use credits generated, such 
credit use must necessarily occur in a compliance year other than the 
one in which the credit was generated. Thus we do not believe that a 
retrospective approach to the Act's 12-month credit life provision is 
consistent with the explicit credit provisions of the Act. In addition, 
we believe that an interpretation leading to a valid life of one year 
after the year in which the RIN was generated is most consistent with 
the program as a whole. In comparison to a single-year valid life for 
RINs, our approach provides some additional compliance flexibility to 
obligated parties as they make efforts to acquire sufficient RINs to 
meet their RVOs each year. This flexibility will have the effect of 
keeping fuel costs lower than they would otherwise be.
    In the comments we received on the NPRM, one objection to our 
proposed approach was that the use of RINs generated in one compliance 
period to satisfy obligations in a subsequent compliance period could 
result in less renewable fuel used in a given year than is set forth in 
the statute. While this is true, we believe this approach is most 
consistent with the Act, as described above. The Act clearly set up a 
credit program with a credit life, meaning Congress intended parties to 
use credits in some cases instead of blending renewable fuel. The Act 
is best read to harmonize all of its provisions. In addition, we note 
that other provisions of the Act may lead to less renewable fuel use in 
a given year than the statutorily-prescribed volumes, but Congress 
adopted them and intended that they could be used. For instance, the 
deficit carryover provision allows any obligated party to fail to meet 
its RVO in one year if it meets the deficit and its RVO in the next 
year. If several obligated parties took advantage of this provision, it 
could result in the nationwide total volume obligation for a particular 
calendar year not being met. In a similar fashion, the statutory 
requirement that every gallon of cellulosic biomass ethanol be treated 
as 2.5 gallons for the purposes of compliance means that the annually 
required volumes of renewable fuel could be met in part by virtual, 
rather than actual, volumes. Finally, the calculation of the renewable 
fuel standard is based on projected nationwide gasoline volumes 
provided by EIA (see Section III.A). If the projected gasoline volume 
falls short of the actual gasoline volume in a given year, the standard 
will fail to create the demand for the full renewable fuel volume 
required by the Act for that year. The Act contains no provision for 
correcting for underestimated gasoline volumes. Additional responses to 
the issues raised by commenters on RIN life can be found in the S&A 
document.
c. Cap on RIN Use To Address Rollover
    As described in Section III.D.3.b above, RINs are valid for 
compliance purposes for the calendar year in which they are generated 
or the following year. We believe that this approach is most consistent 
with the Act's prescription that credits be valid for compliance 
purposes for 12 months as of the date of generation. Our approach is 
intended to address both the risk taken by producers expecting a 
guaranteed demand to cover their expanded production capacity 
investments and the risk taken by obligated parties who need a 
guaranteed supply in order to meet their regulatory obligations under 
this program.
    However, the use of previous year RINs to meet current year 
compliance obligations does create an opportunity for effectively 
circumventing the valid life limit for RINs. This can occur in 
situations wherein the total number of RINs generated each year for a 
number of years in a row exceeds the number of RINs required under the 
RFS program for those years. The excess RINs generated in one year 
could be used to show compliance in the next year, leading to the 
generation of new excess RINs in the next year, causing the total 
number of excess RINs in the market to accumulate over multiple years 
despite the limit on RIN life. The NPRM included examples of how this 
``rollover'' might occur. The rollover issue would in some 
circumstances essentially make the applicable valid life for RINs 
virtually meaningless in practice.
    RIN rollover also undermines the ability of a limit on credit life 
to guarantee a market for renewable fuels. As described in Section 
III.D.3.b, if the natural market demand for ethanol was higher than the 
volumes required under the RFS program for several years in a row, as 
may occur in practice, obligated parties could amass RINs that, in the 
extreme, could be used entirely in lieu of actually demanding ethanol 
in some subsequent year.
    As described in the NPRM, we believe that the rollover issue must 
be addressed. The Act's provision regarding the valid life of credits 
is clearly intended to obtain the benefits associated with a limited 
credit life. Any program structure in which some RINs effectively have 
an infinite life, regardless of the technical life of individual RINs, 
does not appropriately achieve the benefits expected from the Act's 
provision regarding the 12-month life of credits. The authority to 
establish a credit program and to implement a limited life for credits 
includes the authority to limit actions that have the practical effect 
of circumventing this limited credit life.
    To be consistent with the Act, we believe that the rollover issue 
should be addressed in our regulations. However, we also believe that 
the limits to preclude such unhindered rollovers should not preclude 
all previous-year RINs from being used for current-year compliance. To 
accomplish this, we must restrict the number of previous-year RINs that 
can be used for current year compliance. To this end, we proposed a 20 
percent cap on the amount of an obligated party's Renewable Volume 
Obligation (RVO) that can be met using previous-year RINs. After review 
of the comments we received on the NPRM, we have decided to finalize 
this provision. Thus each obligated party will be required to use 
current-year RINs to meet at least 80 percent of its RVO, with a 
maximum of 20 percent being derived from previous-year RINs. Any 
previous-year RINs that an obligated party may have that are in excess 
of the 20 percent cap can be traded to other obligated parties that 
need them. If the previous-year RINs in excess of the 20 percent cap 
are not used by any obligated party for compliance, they will expire. 
The net result will be that, for the market as a whole, no more than 20 
percent of a given year's renewable fuel standard can be met with RINs 
from the previous year.
    As described in the NPRM, we believe that the 20 percent cap 
provides the

[[Page 23935]]

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 the Act. We believe 
this approach also provides the certainty all parties desire in 
implementing the program. The same cap will apply equally to all 
obligated parties, and the cap will be the same for all years, 
providing certainty on exactly how obligated parties must comply with 
their RVO going out into the future. A 20 percent cap will be readily 
enforceable with minimal additional program complexity, as each 
obligated party's annual report will simply provide separate listings 
of previous-year and current-year RINs to establish that the cap has 
not been exceeded. A 20 percent cap will have no impact on who could 
own RINs, their valid life, or any other regulatory provision regarding 
compliance.
    Some NPRM commenters did not perceive a problem with the RIN 
rollover issue and argued for no rollover cap or at least for a more 
flexible one. They pointed to the need for maximum flexibility in 
responding to fluctuations in the market, and they were primarily 
concerned about potential supply problems. For instance, if a drought 
were to reduce the availability of corn for ethanol production, there 
may simply not be sufficient RINs available for compliance purposes. A 
drought situation actually occurred in 1996, and as a result 1996 
ethanol production was 21% less than it had been in 1995. In 1997, 
production had not yet returned to the 1995 levels. Moreover, there is 
no guarantee that future droughts, should they occur, would result in a 
reduction in ethanol production of only 21 percent. As a result, in the 
NPRM we requested comment on whether a higher cap, such as 30 percent, 
would be more appropriate. A number of refiners and refinery 
associations commented that 30 percent would indeed provide them with 
the additional flexibility they would need in the case of a significant 
market disruption. Some requested a cap of 40 percent or even no cap at 
all. These parties also expressed concern that, although the Agency has 
the authority to waive the required renewable fuel volumes in whole or 
in part in the event of inadequate domestic supply, this can occur only 
on petition by one or more states and then only after consultation with 
both the Department of Agriculture and the Department of Energy. Some 
obligated parties expressed concern that such a waiver would not occur 
in a timely fashion. The availability of excess previous-year RINs 
would thus provide compliance certainty in the event that the supply of 
current-year RINs falls below the RFS program requirements and the 
Agency does not waive any portion of the program requirements.
    In contrast to obligated parties, renewable fuel producers provided 
comments on the NPRM indicating that 10 percent would be more 
appropriate. They argued that a 10 percent cap was closer to their 
preferred approach to RIN life in which the Act's 12-month life of a 
credit is interpreted as allowing RINs to be used for compliance 
purposes only in the year in which they are generated.
    We continue to believe that a cap set at 20 percent is appropriate, 
and the comments submitted in response to the NPRM did not provide 
compelling evidence to the contrary. The level of 20 percent is 
consistent with past ethanol market fluctuations. As described above, 
the largest single-year drop in ethanol supply occurred in 1996 and 
resulted in 21% less ethanol being produced than in 1995. While future 
supply shortfalls may be larger or smaller, the circumstances of 1996 
provide one example of their potential magnitude.
    We believe that a cap of 20 percent is a reasonable way to limit 
RIN rollover and provide some assurances to renewable fuel producers 
regarding demand for renewable fuel. A cap of 20 percent also ensures 
that many previous-year RINs can still be used for current year 
compliance, providing some flexibility in the event of market 
disruptions.
    Given the competing needs expressed by renewable fuel producers and 
refiners, a rollover cap of 20 percent also balances the risk taken by 
producers of renewable fuels expecting a guaranteed quantity demanded 
to cover their production capacity investments and the risk taken by 
obligated parties who need a guaranteed supply in order to meet their 
regulatory obligations under this program. We are therefore finalizing 
a rollover cap of 20 percent.
    In the NPRM we also considered an alternative approach whereby we 
would set the cap annually based on the actual excess renewable fuel 
production. We did not propose this approach, and commenters did not 
support it. We have determined that fixing the cap at 20 percent both 
provides certainty to the RIN market and ensures that some minimum 
level of flexibility exists for individual obligated parties even in a 
market without excess RINs.
    We also requested comment on whether the Agency should adopt a 
provision allowing the cap to be raised in the event that supply 
shortfalls overwhelmed the 20 percent cap. Under this conditional 
provision, the Agency would monitor standard indicators of agricultural 
production and renewable fuel supply to determine if sufficient volumes 
of renewable can be produced to meet the RFS program requirements in a 
given year. Prior to the end of a compliance period, if the Agency 
determined that a supply shortfall was imminent, it could raise the cap 
to permit a greater number of previous-year RINs to be used for 
current-year compliance. Although this approach would not change the 
required volumes, it could create some additional temporary 
flexibility. However, we did not propose this provision, and commenters 
did not address it. We do not believe it is necessary, and thus we have 
not finalized it.
    Finally, the cap is designed to prevent the rollover of RINs 
generated two years ago from being used for compliance purposes in the 
current year. No RINs were generated in 2006 when the default standard 
of 2.78 percent was in effect on a collective basis, so the first year 
in which RINs will be generated is 2007. Consequently, the first year 
in which there could be rollover would be 2009. Therefore, we proposed 
that the cap would not be effective until compliance year 2009. Two 
commenters pointed out that this approach could under some scenarios 
lead to a situation in which more than 20 percent of the RINs used for 
compliance purposes in 2008 were actually generated in the previous 
year, 2007. EPA believes that implementing the rollover cap in 2008 
would, indeed, prevent the initiation of an excess buildup of past 
RINs. In addition, it would simplify the regulations, since there would 
be no need for an exception from the RIN cap for 2008. Consequently we 
are finalizing the 20 percent cap to apply to all years, including 
2008.
d. Deficit Carryovers
    The Energy Act also contains a provision allowing an obligated 
party to carry a deficit forward from one year into the next if it 
cannot comply with its RVO. However, deficits cannot be carried over 
two years in a row.
    Deficit carryovers are measured in gallons of renewable fuel, just 
as for RINs and RVOs. If an obligated party does not acquire sufficient 
RINs to meet its RVO in a given year, the deficit is calculated by 
subtracting the total number of RINs an obligated party has acquired 
from its RVO. There are no volume penalties, discounts, or other 
factors included when calculating a

[[Page 23936]]

deficit carryover. As described in Section III.D.1, the deficit is then 
added to the RVO for the next year. The calculation of the RVO as 
described in Section III.A.4 shows how a deficit would be carried over 
into the next year:

RVOi = (Stdi x GVi) + Di-1

Where:

RVOi = The Renewable Volume Obligation for the obligated 
party for year i, in gallons.
Stdi = The RFS program standard for year i, in percent.
GVi = The non-renewable gasoline volume produced by an 
obligated party in year i, in gallons.
Di-1 = Renewable fuel deficit carryover from the previous 
year, in gallons.

    If an obligated party does not acquire sufficient RINs to meet its 
RVO in year i-1, the obligated party must procure sufficient RINs to 
cover the full RVO for year i including the deficit. There are no 
provisions allowing for another year of carryover. If the obligated 
party does not acquire sufficient RINs to meet its RVO for that year 
plus the deficit carryover from the previous year, it will be in 
noncompliance.
    The Act indicates that deficit carryovers are to occur due to 
``inability'' to generate or purchase sufficient credits. We believe 
that obligated parties will make a determined effort to satisfy their 
RVO on an annual basis and that a deficit will demonstrate that they 
were unable to do so. Thus, we did not propose that any particular 
demonstration of ``inability'' be a prerequisite to the ability of 
obligated parties to carry deficits forward. However, one commenter 
requested that we should establish some sort of standard or threshold 
that obligated parties must meet before they would be allowed to use 
the deficit carryover provision. Although the commenter provided no 
suggestions regarding how such a threshold could be established, he 
indicated that in the absence of such a threshold obligated parties 
could potentially use the deficit carryover provision to undermine the 
amount of actual renewable fuel used in a given year.
    We agree that the deficit carryover provision could result in less 
renewable fuel being consumed in a given year than is required by the 
Act, especially if several obligated parties took advantage of it at 
the same time. However, in any given year some parties may be making up 
deficits from a prior year, while other parties might be generating 
deficits. This fact will tend to reduce the net effect in any given 
year, and regardless, the deficit in demand in one year will by 
regulatory requirement be made up in the following year. Finally, any 
threshold we could set to demonstrate an obligated party's inability to 
generate or purchase sufficient credits would likely require a 
comprehensive investigation of their opportunities to acquire RINs. 
Such investigations would consume Agency resources that would be better 
spent, in terms of ensuring that the goals of the Act are met, on other 
compliance enforcement matters. Therefore, we have not set any 
thresholds in the final rule.
4. Provisions for Exporters of Renewable Fuel
    As described in Section III.D.2.a, we believe that U.S. consumption 
of renewable fuel as motor vehicle fuel can be measured with 
considerable accuracy through the tracking of renewable fuel production 
and importing records. This is the basis for our RIN-based system of 
compliance. However, exports of renewable fuel must be accounted for 
under this approach. For instance, if a gallon of ethanol is produced 
in the U.S. but consumed outside of the U.S., the RIN associated with 
that gallon is not valid for RFS compliance purposes since the RFS 
program is intended to require a specific volume of renewable fuel to 
be consumed in the U.S. Exports of renewable fuel currently represent 
about 5 percent of U.S. production, though the exact value varies each 
year.
    To ensure that renewable fuels exported from the U.S. cannot be 
used by an obligated party for RFS compliance purposes, the RINs 
associated with that exported renewable fuel must be removed from 
circulation. For this final rule we have concluded that it should be 
the exporter's responsibility to account for exported renewable fuel in 
our RIN-based program. We are therefore requiring that an RVO be 
assigned to each exporter that is equal to the annual volume of 
renewable fuel it exported. Just as for obligated parties, then, the 
exporter is required to acquire sufficient gallon-RINs to meet its RVO. 
If the exporter purchases renewable fuel directly from a producer, that 
renewable fuel will come with associated gallon-RINs which can then be 
applied to its RVO under our program. In this circumstance, the 
exporter will not need to acquire RINs from any other source. If, 
however, the exporter receives renewable fuel without the associated 
RINs, it will need to acquire RINs from some other source in order to 
meet its RVO.
    In the NPRM we presented an alternative approach which would have 
increased the obligation placed on refiners and importers of gasoline 
based on the volume of renewable fuel exported. One commenter supported 
this alternative approach, explaining that the proposed approach of 
requiring the exporter to acquire sufficient RINs to offset an RVO 
equal to the exported volume would place a significant recordkeeping 
burden on exporters. This commenter also expressed concern that 
exporters would receive no value in return for compliance with an RVO. 
We do not believe that these are compelling reasons to place the burden 
for exported renewable fuel on obligated parties. Not only would this 
alternative approach have required an estimate of the volume of 
renewable fuel exported in the next year, but would also mean that 
every obligated party would share in accumulating RINs to cover the 
activities of other parties not under their control.
    In the NPRM we pointed out that in specific circumstances involving 
exports of renewable fuels, the need for RINs might not be necessary. 
For instance, if the exporter was wholly owned by a renewable fuel 
producer, there would be no need to generate RINs for the exported 
product. We therefore proposed to allow exported product to be excluded 
from the exporter's RVO if the exporter was also the producer and no 
RINs were generated for that product. However, one commenter pointed 
out that this approach could lead to confusion regarding which gallons 
should have an assigned RIN and which should not, given the complex 
nature of tracking volumes of renewable fuel. As a result we have 
determined that this provision should be eliminated. Our final 
regulations require producers to assign RINs to all renewable fuel, 
regardless of whether it is exported. In this case the renewable 
producer would merely use these RINs to cover its obligation as an 
exporter.
    As described in Section III.D.2, there are cases in which there is 
not a one-to-one correspondence between gallons in a batch of renewable 
fuel and the gallon-RINs generated for that batch. If the RVO assigned 
to the exporter were based strictly on the actual volume of the 
exported product, it would not necessarily capture all the gallon-RINs 
which were generated for that exported volume. Thus we are requiring 
that the RVO assigned to an exporter be based not on the actual volume 
of renewable fuel exported, but rather on a volume adjusted by the 
Equivalence Value assigned to each batch. The Equivalence Value is 
represented by the RR code within the RIN as described in Section 
III.D.2.a. Thus the exporter must multiply the actual volume of a batch 
by

[[Page 23937]]

that batch's Equivalence Value to obtain the volume used to calculate 
the RVO.
    In cases wherein an exporter obtains a batch of renewable fuel 
whose RIN has already been separated by an obligated party or blender, 
the exporter may not know the Equivalence Value. We are requiring that 
for such cases the exporter use the equivalence value applicable to 
that type of renewable fuel (e.g., 1.5 for biodiesel). However, in the 
case of ethanol, the same product could have been produced as corn 
ethanol or cellulosic ethanol. Thus, in the case of ethanol, if the 
exporter does not know the equivalence value we are requiring that the 
exporter use the actual volume of the batch to calculate its RVO. This 
will introduce some small error into the calculation of the RVO for 
cases in which the ethanol had in fact been assigned an Equivalence 
Value of 2.5. However, we believe that the potential impact of this on 
the overall program will be exceedingly small.
5. How Will the Agency Verify Compliance?
    The primary means through which the Agency will verify an obligated 
party's compliance with its RVO will be the annual compliance 
demonstration reports. These reports will include a variety of 
information required for compliance and enforcement, including the 
demonstration of compliance with the previous calendar year's RVO, a 
list of all transactions involving RINs, and the tabulation of the 
total number of RINs owned, used for compliance, transferred, retired 
and expired. Reporting requirements for obligated and non-obligated 
parties are covered in detail in Section IV.
    In its annual reports, an obligated party will be required to 
include a list of all RINs held as of the reporting date, divided into 
a number of categories. For instance, a distinction must be made 
between current-year RINs and previous-year RINs as follows:
    Current-year RINs: RINs that came into existence during the 
calendar year for which the report is demonstrating compliance.
    Previous-year RINs: RINs that came into existence in the calendar 
year preceding the year for which the report is demonstrating 
compliance.
    The report must also indicate which RINs have been used for 
compliance with the RVO including any potential deficit, which current-
year RINs have not been used for compliance and are therefore valid for 
compliance the next year, and which previous-year RINs have not been 
used for compliance and therefore expire. The report must also include 
a demonstration that the obligated party had not exceeded the 20 
percent cap to address RIN rollover, as described in Section III.D.3.c.
    In order to verify compliance for each obligated party, the primary 
Agency activity will involve the validation of RINs. The Agency will 
perform the following four basic elements of RIN validation:
    (1) RINs used by an obligated party to comply with its RVO will be 
checked to ensure that they are within their two-year valid life. The 
RIN itself will contain the year of generation, so this check involves 
only an examination of the listed RINs.
    (2) All RINs owned by an obligated party will be cross-checked with 
reports from renewable fuel producers to verify that each RIN had in 
fact been generated.
    (3) All RINs used by an obligated party for compliance purposes 
will be cross-checked with annual reports from other obligated parties 
to ensure that no two parties used the same RIN to comply.
    (4) Previous-year RINs used for compliance purposes will be checked 
to ensure that they do not exceed 20 percent of the obligated party's 
RVO.
    In cases where a RIN is highlighted under suspicion of being 
invalid, the Agency will then need to take additional steps to resolve 
the issue. In general this will involve a review of RIN transfer 
records submitted quarterly to the Agency by all parties in the 
distribution system that held the RINs. RIN transfers will be recorded 
through EPA's Central Data Exchange as described in Section IV. These 
RIN transfer records will permit the Agency to identify all 
transaction(s) involving the RINs in question. The Agency can then 
contact liable parties and take appropriate steps to formally 
invalidate a RIN improperly claimed by a particular party. Additional 
details of the liabilities and prohibitions attributed to parties in 
the distribution system are discussed in Section V.

E. How Are RINs Distributed and Traded?

    Under our final program structure, a Renewable Identification 
Number (RIN) must (with certain exceptions) be generated for all 
renewable fuel produced or imported into the U.S., and RINs must be 
acquired by obligated parties for use in demonstrating compliance with 
the RFS requirements. However, as described in the NPRM, there are a 
variety of ways in which RINs could theoretically be transferred from 
the point of generation by renewable fuel producers to the obligated 
parties that need them.
    EPA's final program was developed in light of the somewhat unique 
aspects of the RFS program. As discussed earlier, under this program 
the refiners and importers of gasoline are the parties obligated to 
comply with the renewable fuel requirements. At the same time, refiners 
and importers do not generally produce or blend renewable fuels at 
their facilities and so are dependent on the actions of others for the 
means of compliance. Unlike EPA's other fuel programs, the actions 
needed for compliance largely center on the production, distribution, 
and use of a product by parties other than refiners and importers. In 
this context, we believe that the RIN transfer mechanism should focus 
primarily on facilitating compliance by refiners and importers and 
doing so in a way that imposes minimum burden on other parties and 
minimum disruption of current mechanisms for distribution of renewable 
fuels.
    Our final program does this by relying on the current market 
structure for ethanol distribution and use and avoiding the need for 
creation of new mechanisms for RIN distribution that are separate and 
apart from this current structure. Our program basically requires RINs 
to be transferred with renewable fuel until the point at which the 
renewable fuel is purchased by an obligated party or is blended into 
gasoline or diesel fuel by a blender. This approach allows the RIN to 
be incorporated into the current market structure for sale and 
distribution of renewable fuel, and avoids requiring refiners to 
develop and use wholly new market mechanisms. While the development of 
new market mechanisms to distribute RINs is not precluded under our 
program, it is also not required.
    In the NPRM the Agency also evaluated several options for 
distributing RINs other than the option incorporated into today's rule. 
We are not finalizing these alternatives because they tend to require 
the development of new market mechanisms, as compared to relying on the 
current market structure for distribution of ethanol, and they are less 
focused on facilitating compliance for the obligated parties.
1. Distribution of RINs With Volumes of Renewable Fuel
    We are requiring that RINs be transferred with volumes of renewable 
fuel as they move through the distribution system, until ownership of 
those volumes is assumed by an obligated party, exporter, or a party 
that converts the renewable fuel into motor vehicle fuel. At such time, 
RINs can be

[[Page 23938]]

separated from the volumes and freely traded. This approach places 
certain requirements on anyone who takes ownership of renewable fuels, 
including renewable fuel producers, importers, marketers, distributors, 
blenders, and terminal operators.
a. Responsibilities of Renewable Fuel Producers and Importers
    The initial generation of RINs and their assignment to batches of 
renewable fuel will be the sole responsibility of renewable fuel 
producers and renewable fuel importers. As described in Section 
III.D.1, volumes of renewable fuel can be measured most accurately and 
be more readily verified at these originating locations.
    The final rule defines a batch of renewable fuel as a volume that 
has been assigned a unique batch-RIN. This simple and flexible 
definition of a batch allows renewable fuel producers and importers to 
construct each batch-RIN based on the particular circumstances 
associated with the batch. In this context, a batch is not confined to 
the volume that can be held in a tank, but instead can include a 
significantly larger volume. However, we are placing two limits on the 
volumes of renewable fuel that are identified as a single batch. First, 
the RIN contains only enough digits to permit the assignment of 
99,999,999 gallon-RINs to a single batch. For corn-ethanol with an 
Equivalence Value of 1.0, this means that a single batch can be 
comprised of up to 99,999,999 gallons of ethanol. In contrast, for 
biodiesel with an Equivalence Value of 1.5, a single batch can contain 
up to 66,666,666 gallons of biodiesel. Second, in order to provide more 
clarity in the event that an investigation of a party's volume and RIN 
generation records is conducted, we are also limiting a batch to the 
maximum volume that is produced or imported by the renewable fuel 
producer or importer within a calendar month. Within these two limits, 
producers and importers can define batches of renewable fuel according 
to their own discretion and practices, including using individual 
tankfulls to represent each batch. These parties must designate a 
unique serial number for each batch (RIN code BBBBB) and specify its 
Equivalence Value. The batch-RIN will identify all the gallon-RINs 
assigned to the batch. See Section III.D.2.a for details on the format 
for RINs.
    In the NPRM, we proposed different approaches to the assignment of 
standard-value RINs and extra-value RINs. Under the proposal, extra-
value RINs could be generated by the renewable fuel producer in cases 
where the renewable fuel in question had an Equivalence Value greater 
than 1.0. We proposed that all standard-value RINs must be assigned to 
volumes of renewable fuel, but that producers should have the option of 
whether to assign extra-value RINs to batches. We took this approach in 
part out of concern that the assignment of extra-value RINs to volumes 
would mean that the number of gallon-RINs assigned to a batch could be 
greater than the number of gallons in that batch. This was of 
particular concern for ethanol, since a tank could contain both corn-
ethanol and cellulosic ethanol. When volume was withdrawn from the 
tank, it would have been unclear whether the volume should be assigned 
the extra-value RINs or not. In the process of designing the proposed 
program structure to accommodate such situations, however, the program 
became more complicated than it needed to be.
    In response to the NPRM, some commenters requested that extra-value 
RINs be treated just like standard-value RINs. Specifically, some 
obligated parties, as well as gasoline marketers and distributors, 
argued that all RINs, be they standard-value or extra-value, should be 
required to travel with volumes of renewable fuel so that they will all 
be equally available to the obligated parties that need them for 
compliance. These commenters expressed concern that some producers may 
not release extra-value RINs, if given the choice, in an effort to 
drive up demand for renewable fuel.
    After further consideration, we have determined that in most cases 
there is no need to treat extra-value RINs differently from standard-
value RINs in terms of whether each should be assigned to batches of 
renewable fuel by the producer or importer. Therefore, for most 
renewable fuels we are finalizing a requirement that all RINs be 
assigned to batches of renewable fuel by the producer or importer. 
Since each renewable fuel with a different Equivalence Value is a 
distinct fuel, producers and importers will still receive the added 
value of extra-value RINs that are assigned to volumes of renewable 
fuel if those volumes are priced appropriately in comparison to other 
renewable fuels with different Equivalence Values. The only exception 
to this is cellulosic biomass and waste-derived ethanol. Producers of 
such ethanol may have difficulty marketing their product at prices 
different than that for corn ethanol given the fungible distribution 
system for ethanol. The added value of the extra-value RINs may not be 
reflected in the price and as a result the producer may not receive any 
economic benefit from them. Therefore, for the case of cellulosic 
biomass and waste-derived ethanol we are maintaining the ability of the 
producer, should they so choose, to retain the extra value and not 
assign these RINs to the renewable fuel that they represent. In such 
cases, the producer of the cellulosic biomass or waste-derived ethanol 
would be required to change the K code from 1 to 2 in order to 
designate these extra RINs as separated RINs.
    This approach is also consistent with one of the primary 
motivations for the approach described in our NPRM, namely that each 
gallon-RIN be allowed to have a value of 1.0 to facilitate trading. 
Even though different renewable fuels will have different Equivalence 
Values and therefore different numbers of gallon-RINs per gallon, each 
gallon-RIN will still count as one gallon of renewable fuel for RFS 
compliance purposes.
    However, the distinction between standard-value RINs and extra-
value RINs is no longer necessary. The total number of gallon-RINs that 
can be generated for a given batch of renewable fuel will be determined 
directly by its Equivalence Value as described in Section III.D.2.b, 
and all such gallon-RINs will be summarized in a single batch-RIN 
assigned to a batch. In cases where the Equivalence Value is greater 
than 1.0, there will be more gallon-RINs assigned to a batch of 
renewable fuel than gallons in that batch. Once again, in the context 
of the changes we are making to the RIN distribution program structure 
as described in Section III.E.1.b below, we do not believe that this 
will in any way complicate the process of distributing RINs with 
renewable fuel. For the specific case of cellulosic biomass or waste-
derived ethanol with an Equivalence Value of 2.5, producers will be 
required to assign only one gallon-RIN to each gallon of ethanol, each 
of which has a K code value of 1. The additional 1.5 gallon-RINs that 
can be generated for each gallon can remain unassigned, and thus be 
assigned a K code value of 2.
    In addition to cases where the Equivalence Value is greater than 
1.0, there are several other cases in which the gallon-RINs assigned to 
a batch will not exactly correspond to the number of gallons in that 
batch. First, if a renewable fuel has an Equivalence Value less than 
1.0, then there will be fewer gallon-RINs than gallons in the batch. 
Such potential circumstances are described in Section III.D.2.c. RINs 
may also not correspond exactly to gallons if the density of the batch 
changes due to changes in temperature. For instance,

[[Page 23939]]

under extreme changes in temperature, the volume of a batch of ethanol 
can change by 5 percent or more. For this reason we are requiring that 
all batch volumes be corrected to represent a standard condition of 60 
[deg]F prior to the assignment of a RIN. For ethanol,\37\ we are 
requiring that the correction be done as follows:\38\
---------------------------------------------------------------------------

    \37\ An appropriate temperature correction for other renewable 
fuels must likewise be used.
    \38\ Derived from ``Fuel Ethanol Technical Information,'' Archer 
Daniels Midland Company, v1.2, 2003.

---------------------------------------------------------------------------
Vs,e = Va,e x (-0.0006301 x T + 1.0378)

Where:

Vs,e = Standard volume of ethanol at 60 [deg]F, in 
gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.

Since batches of ethanol are generally sold using standard volumes 
rather than actual volumes, this approach to assigning RINs to batches 
is consistent with current practices and will maintain the one-to-one 
correspondence between the volume block in the batch-RIN and the 
standardized volume of the batch. We are requiring a similar approach 
for biodiesel, where the volume correction must be calculated using the 
following equation:\39\
---------------------------------------------------------------------------

    \39\ Derived from R.E. Tate et al., ``The densities of three 
biodiesel fuels at temperatures up to 300 [deg]C,'' Fuel 85 (2006) 
1004-1009, Table 1 for soy methyl ester.

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

Where:

Vs,b = Standard volume of biodiesel at 60 [deg]F, in 
gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.

    Consistent with the NPRM, we are requiring that RIN generation 
begin at the same time that the renewable fuel standard becomes 
applicable to obligated parties. Thus RINs must be generated for all 
renewable fuel produced or imported on or after September 1, 2007. 
Since many producers and importers will have renewable fuel in 
inventory at the start of the program that was produced prior to 
September 1, 2007, we are also allowing them to generate RINs for any 
renewable fuel that they own on September 1, 2007. This provision 
ensures that every gallon that a producer or importer sells starting on 
September 1, 2007 can have an assigned RIN, and obligated parties that 
take ownership of renewable fuel directly from a producer or importer 
will have greater assurance of receiving RINs at the start of the 
program. Since RINs are not assigned to volumes until those volumes are 
transferred to another party, this approach also provides producers and 
importers of renewable fuel the flexibility to determine which of the 
volumes they own on September 1, 2007 constitute production as of the 
start of the program.
    Although a RIN is generated when renewable fuel is produced or 
imported, we do not define the point of production. However, the RIN 
must be assigned to a batch no later than the point in time when 
ownership of the batch is transferred from the producer or importer to 
another party. If ownership of the batch is retained by the producer or 
importer after the batch leaves the originating facility, the RIN need 
not be transferred along with the batch on product transfer documents 
identifying transfer of custody.
    The means through which RINs are transferred with volumes of 
renewable fuel will in some respects be left to the discretion of the 
renewable fuel producer or importer. The primary requirement would be 
that the RIN transfer be recorded on a product transfer document (PTD). 
The PTD can be included in any form of standard documentation that is 
already associated with or used to identify title to the volume or can 
be a separate document as described below. In many cases an invoice 
could serve this purpose. As in other fuels programs, we believe the 
PTD requirement can be met by including the required information 
generated and transferred in the normal course of business.
    RINs are transferable in the context of the RFS program and 
initially must be transferred along with ownership of a volume of 
renewable fuel. The approach that a producer or importer takes to the 
transfer or sale of RINs and volumes would be at their discretion, 
under the condition that the RIN and volume be transferred or sold on 
the same day and to the same party. Based on comments received, we are 
also permitting the transfer of RINs to be done in a separate PTD from 
the PTD used to transfer ownership of the volume of renewable fuel. 
This will provide some additional flexibility to parties who take 
ownership of renewable fuel with assigned RINs, permitting IT systems 
managing RIN transfers to be more easily incorporated into existing 
business management systems. Thus a party may use two separate PTDs, 
one for the volume and another for the RINs. However, transfer of the 
RINs must occur on the same day that transfer of the volume occurred, 
and the two PTDs must contain sufficient information to uniquely cross-
reference them. In many cases an electronic transfer will suffice if 
sufficient information about the transfer is recorded. In the case of 
such parallel PTDs, we are also requiring that the PTD transferring 
ownership of the volume must indicate whether RINs are being 
transferred and the number of gallon-RINs being transferred, though it 
need not list the actual RINs.
    As described in Section III.E.1.b below, while assigned RINs must 
always be transferred to another party with a volume of renewable fuel, 
we are allowing any party that received assigned RINs with renewable 
fuel to thereafter transfer anywhere from zero to 2.5 gallon-RINs with 
each gallon of renewable fuel. This provision provides the flexibility 
to transfer more assigned RINs with some volumes and less assigned RINs 
with other volumes depending on the business circumstances of the 
transaction and the number of RINs that the seller has available. 
However, for producers and importers of renewable fuel, this level of 
flexibility could contribute to short-term hoarding that was the 
primary concern expressed by obligated parties during development of 
the proposed program. Therefore we are also finalizing a provision that 
requires producers and importers to transfer assigned gallon-RINs with 
gallons such that the ratio of assigned gallon-RINs to gallons is equal 
to the equivalence value for the renewable fuel. Since this is not 
possible for exempt small volume producers, or when a producer or 
importer obtains renewable fuel from another party without assigned 
RINs, exceptions are made in these cases.
    We received comment that EPA should require a purchaser of imported 
gasoline who subsequently blends renewable fuel into the imported 
gasoline to transfer the RINs associated with the renewable fuel back 
to the importer of the gasoline. The commenter suggested that this 
requirement would ensure that the importer of the gasoline obtains all 
the RINs associated with the renewable fuel blended into that gasoline 
in cases where the importer has a long-term contractual agreement with 
the party that purchases the gasoline and adds the renewable fuel. 
However, we do not believe that such a provision is warranted. The RFS 
program places the renewable fuels obligation on parties based on 
ownership of the gasoline at the refiner or importer level. We believe 
this approach is the most effective way to implement and enforce the 
renewable fuels requirement. We also believe it is appropriate to allow 
parties who add the renewable fuel to gasoline, including blenders, to 
separate RINs from the renewable fuel volume and to have the right to 
sell those RINs to any party. Individual parties may agree that,

[[Page 23940]]

in certain situations, it would be appropriate for the RINs to be 
transferred from the renewable fuels blender to the importer of the 
gasoline. In such cases, the parties may make contractual arrangements 
for the transfers. We do not believe it would be appropriate or 
workable for EPA to require such transfers.
    The NPRM did not specify whether RINs should be generated for and 
assigned to renewable fuel that is already contained in imported 
gasoline (for example, a blend of 10 percent ethanol and 90 percent 
gasoline). Since the renewable fuel contained in imported gasoline is 
part of the total volume of renewable fuel in gasoline sold or 
introduced into commerce in the U.S., we believe it is appropriate to 
treat it as any other imported renewable fuel. Thus, we believe it 
would be appropriate for importers to assign RINs to renewable fuel 
contained in imported gasoline. However, the volume of renewable fuel 
contained in imported gasoline is very small in comparison to the 
volume requirements of the RFS program. If an importer of gasoline 
containing renewable fuel imports less than 10,000 gallons per year of 
renewable fuel, then that party is not required to generate RINs. But a 
small volume importer that chooses to generate and assign RINs to any 
volume of renewable fuel in imported gasoline is required to fulfill 
all of the requirements that apply to renewable fuel importers under 
the RFS rule, in addition to all of the requirements that apply to 
gasoline importers as obligated parties. An importer that assigns RINs 
to the renewable fuel in imported gasoline may separate the RINs from 
the renewable fuel, since the renewable fuel has been blended into 
gasoline.
    Regardless of a small volume importer's decision to generate and 
assign RINs to renewable fuel contained in imported gasoline, an 
importer that imports any gasoline containing renewable fuel must 
include the gasoline portion of the imported product in the volume used 
to determine the importer's renewable fuel obligation (and exclude the 
renewable fuel portion of the batch). RINs must be assigned to imported 
renewable fuels that are not contained in gasoline at the time of 
importation, unless less than 10,000 gallons of renewable fuel are 
imported per year.
b. Responsibilities of Parties That Buy, Sell, or Handle Renewable 
Fuels
    Volumes of renewable fuel can be transferred between many different 
types of parties as they make their way from the production or import 
facilities where they originated to the places where they are blended 
into conventional gasoline or diesel. Some of these parties take 
custody but not ownership of these volumes, storing and transmitting 
them on behalf of those who retain ownership. Other parties take 
ownership but not custody, such as a refiner who purchases ethanol and 
has it delivered directly to a blending facility. Thus prior to 
blending, each volume of renewable fuel can be owned or held by any 
number of parties including marketers, distributors, terminal 
operators, and refiners.
    In the NPRM, we proposed that in general all parties that assume 
ownership of any volume of renewable fuel would be required to transfer 
all RINs assigned to that volume to another party to whom ownership of 
the volume is being transferred. The only exceptions to the requirement 
that RINs be transferred with volumes would be for parties who are 
obligated to meet the renewable fuel standard and parties who convert 
the renewable fuel into motor vehicle fuel. Commenters overwhelmingly 
supported this approach to the distribution of RINs assigned to volumes 
of renewable fuel, and as a result we are adopting this approach in our 
final program. In this context, we are also clarifying that parties 
taking custody of a volume of renewable fuel but not ownership of that 
volume would have no responsibilities with regard to the transfer of 
RINs.
    However, in response to the NPRM, several stakeholders apprised us 
of certain aspects of our proposed program that would limit the 
intended fungibility of RINs assigned to volumes of renewable fuel. 
While the goal of our proposed program was to permit RINs to be 
interchangeable with one another and to permit one assigned RIN to be 
exchanged with another RIN, our proposed regulations did not 
sufficiently capture this level of fungibility. Instead, the proposed 
regulations effectively required that a specific RIN assigned to a 
specific gallon of renewable fuel must remain assigned to that specific 
gallon as it travels through the distribution system. This approach was 
taken in order to accommodate the legitimate existence of some volumes 
of renewable fuel without assigned RINs, and some assigned RINs that 
have no corresponding volume. These situations can occur in the 
distribution system for several reasons, such as the following:
     RINs can be separated from renewable fuel by obligated 
parties or blenders, and the renewable fuel re-introduced into the 
distribution system.
     Small volume producers are exempt from generating and 
assigning RINs to their product.
     At the start of the program, some parties may have 
renewable fuel in their inventories that have not been assigned a RIN.
     Batches of renewable fuels with Equivalence Values less 
than 1.0 will have fewer gallon-RINs than gallons.
     Batch volumes can swell or shrink due to temperature 
changes.
     Batch volumes can shrink due to evaporation, spillage, 
leakage, or accidents.
     Volume metering imprecision.
    Indeed, if the program could be designed such that every gallon in 
the distribution system always had an assigned RIN, the complete 
fungibility of RINs would be straightforward. However, this is not the 
case.
    In order to make assigned RINs more fungible, we are finalizing a 
modified version of our proposed approach. Consistent with the NPRM, no 
party will be permitted to change a RIN assigned to a volume of 
renewable fuel into an unassigned (separated) RIN except for those 
parties explicitly given the right to do so (for example, obligated 
parties and oxygenate blenders). Also consistent with the NPRM, any 
party not authorized to separate an assigned RIN that takes ownership 
of a RIN assigned to a volume of renewable fuel cannot transfer 
ownership of that RIN to another party without simultaneously 
transferring an appropriate volume of renewable fuel.
    However our final regulations allow any party to transfer a volume 
of renewable fuel without assigned RINs, or with a different number of 
assigned RINs than were received with the renewable fuel, as long as 
the number of assigned gallon-RINs held by that party at the end of a 
quarter is no higher than the number of gallons it owns at the end of 
the quarter. This will provide parties with the flexibility to decide 
which RINs are transferred with which volumes, and to transfer some 
volumes without RINs if the party took ownership of some volumes 
without assigned RINs. Our final regulations require only that the 
number of gallon-RINs held by a party at the end of a quarter be no 
higher than the number of gallons held by that party, adjusted by their 
Equivalence Value. Aside from spillage, evaporation, or volume metering 
imprecision, the only way that the number of gallon-RINs that are held 
by a party could be higher than the number of gallons held (adjusted 
for their Equivalence Value) is if that party transferred some volume 
without RINs. In such a case the excess RINs held

[[Page 23941]]

would be deemed to have been separated from renewable fuel, in 
violation of the prohibition against separating RINs.
    While this approach creates more flexibility for parties that hold 
assigned RINs, it requires three additional changes to the proposed 
regulations. First, we are requiring parties that hold assigned RINs to 
also report the volumes of renewable fuel held at the end of each 
quarter. While the NPRM did not propose that volumes held be reported, 
we believe that the additional burden on parties holding assigned RINs 
will be minimal. The NPRM proposed that the recordkeeping requirements 
include information on all renewable fuel volumes transferred, so under 
the proposal parties holding assigned RINs would in general already 
have the information available. In addition, we are not requiring that 
all volumes held at any time during the quarter be reported, nor are we 
requiring that all volumes transferred be reported. Rather, parties 
will be required only to report the total volume of renewable fuel and 
the total number of gallon-RINs held on the last day of a quarter, in 
addition to other information regarding RINs held and transferred.
    Second, our modified approach requires that we distinguish between 
RINs assigned to renewable fuel and RINs that have already been 
separated from renewable fuel, since only assigned RINs would be 
subject to the end-of-quarter comparison of RINs held and volumes held. 
We have chosen to use the K code in the RIN for this purpose, since it 
no longer serves the purpose of distinguishing between standard-value 
and extra-value RINs. The K code has also been moved to the beginning 
of the RIN to make its value more prominent. RINs assigned to renewable 
fuel must have a K code of 1. Parties who legally separate a RIN from 
renewable fuel must change the K code for that RIN to a value of 2. The 
RIN then formally becomes an unassigned RIN that can be transferred 
independent of renewable fuel volumes. The end-of-quarter comparisons 
between RINs held and volumes held apply only to RINs with a K value of 
1.
    Third, we are requiring quarterly reporting in addition to annual 
reports for RINs held and transferred. In the NPRM we took comment on 
requiring quarterly reporting for various reasons. We received both 
comments supporting and opposing quarterly reporting. As discussed 
further in Section IV, we are requiring quarterly reporting in this 
final rule. Under our modified program structure, quarterly reporting 
will be necessary to ensure that RINs are available for obligated 
parties' annual compliance. Quarterly reports will provide us with the 
ability to monitor the activities of marketers and distributors in real 
time to ensure that they are transferring RINs with renewable fuel, and 
to address potential violations as soon as they arise.
    As discussed in Section III.E.1.a above, we are requiring that 
producers and importers of renewable fuel assign all RINs to volumes of 
renewable fuel, consistent with our proposed approach to standard-value 
RINs. As a result, downstream parties can legitimately hold more 
gallon-RINs than gallons if some of the renewable fuel has an 
Equivalence Value greater than 1.0. In the context of our modified 
approach to RIN distribution, this fact must be taken into account in 
the end-of-quarter comparison of gallon-RINs held and gallons held. 
Thus the following equation must be satisfied at the end of each 
quarter by each party that has taken ownership of any assigned RINs:

[Sigma](RIN)D <= 
[Sigma](VsixEVi)D

Where:

D = Last day of a quarter (Jan-Mar, Apr-Jun, Jul-Sep, Oct-Dec).
[Sigma](RIN)D = Sum of all assigned gallon-RINs with a K 
code of 1 that are owned on the last day of the quarter.
(Vsi)D = Volume i of renewable fuel owned on 
the last day of the quarter, standardized to 60 [deg]F, in gallons.
EVi = Equivalence Value representing volume i.
[Sigma](VsixEVi)D = Sum of all 
volumes of renewable fuel owned on the last day of the quarter, 
multiplied by their respective equivalence values.

    Under our fungible distribution system, the RINs received with a 
volume of renewable fuel may not be the RINs originally generated to 
represent that particular volume. Thus the Equivalence Value for a 
volume of renewable fuel cannot be based on the RR code of associated 
RINs, but instead should be determined from the composition of the 
renewable fuel. If the Equivalence Value for a volume of renewable fuel 
cannot be determined from its composition, it should be assumed to be 
1.0. However, in the specific case of ethanol the owner may not know if 
a volume can be categorized as cellulosic biomass ethanol or waste-
derived ethanol. Thus for volumes of ethanol held at the end of a 
quarter, the Equivalence Value should be assumed to be 2.5 to ensure 
that a party can legitimately hold more RINs than gallons.
    The above equation ensures that the total number of gallon-RINs 
that can be held by a party at the end of a quarter is no greater than 
the number of gallon-RINs he could have received given the volume of 
renewable fuel that he owns. Parties that do not satisfy the above 
equation are deemed to be in violation of the prohibition against 
separating RINs from volumes.
    Under our modified approach to RIN distribution, it might be 
possible for a party who owns volumes of renewable fuel with assigned 
RINs to hold onto all the RINs until near the end of a quarter while 
selling volume without RINs. Then, in order to comply with the above 
equation, the party could transfer all assigned RINs with a single 
volume of renewable fuel prior to the last day of the quarter. This 
approach would amount to short-term hoarding. To prevent it, we are 
also placing a cap on the maximum number of gallon-RINs that can be 
transferred with any gallon of renewable fuel. The cap is dictated by 
the maximum number of gallon-RINs that a party could receive with a 
volume of renewable fuel, which is 2.5 in the case of cellulosic 
biomass ethanol or waste-derived ethanol. For a party that took 
ownership of these types of renewable fuel, we must allow them to 
transfer up to 2.5 gallon-RINs with each gallon.
    We are also aware that there are situations in which the volume 
transferred to another party might be smaller than the volume 
originally received. This could occur due to fuel evaporation, 
spillage, leakage, or volume metering imprecision, and would have the 
effect of raising the ratio of gallon-RINs held to gallons held. For 
spillage/leakage involving significant volumes, we have developed a 
mechanism for formally retiring the RINs associated with the lost 
volume. See Section IV. Smaller volume losses can be accommodated by a 
RIN transfer cap of 2.5, which would in general allow RINs associated 
with lost volume to be transferred with remaining volume. In the rare 
case that a party takes ownership of only cellulosic biomass ethanol or 
waste-derived ethanol and experiences some small volume loss, he can 
take ownership of a small volume of some other form of renewable fuel 
with an Equivalence Value less than 2.5. This will permit him to 
transfer RINs associated with lost volume to another party while still 
meeting the RIN transfer cap of 2.5.
    Our program is designed to allow RIN transfer and documentation to 
occur as part of normal business practices in the context of renewable 
fuel distribution. Thus the incremental costs of transferring RINs with 
volumes is expected to be minimal. Marketers and distributors must 
simply add the RIN to product transfer documents such as

[[Page 23942]]

invoices, and record the RINs in their records of volume purchases and 
sales.
    Finally, the final rule also provides that a foreign entity may 
apply to EPA for approval to own RINs. As an approved foreign RIN 
owner, the foreign entity will be able to obtain, sell, transfer and 
hold both assigned and separated RINs. An approved foreign RIN owner 
will be required to comply with all requirements that apply to domestic 
RIN owners under the RFS rule. In addition, similar to other fuels 
programs, an approved foreign RIN owner will be required to comply with 
additional requirements designed to ensure that enforcement of the RFS 
regulations at the foreign RIN owner's place of business will not be 
compromised.
c. Batch Splits and Batch Mergers
    In the RIN distribution approach proposed in the NPRM, RINs 
assigned to a given volume of renewable fuel remained assigned to that 
volume as it moved through the distribution system. In that context, 
batch splits and batch mergers required special treatment. We discussed 
the need for protocols to ensure that RINs assigned to parent batches 
were appropriately distributed among daughter batches, and that RINs 
assigned to batches that were merged were all re-assigned to the new 
combined batch. The proposed regulations included some restrictions on 
how parent batch RINs were to be apportioned to daughter batches during 
splits, but fell short of prescribing a detailed batch split protocol. 
Nevertheless, commenters by and large did not address these protocols 
in their comments.
    The need for protocols for batch splits and batch mergers was 
directly related to the NPRM's approach to the distribution of RINs 
with volumes of renewable fuel. As described in Section III.E.1.b 
above, we are modifying our approach to permit assigned RINs to be more 
fungible. As a result, there is no need for the regulations to specify 
any batch splitting or batch merging protocols.
    Under our final regulations, parties taking ownership of volumes of 
renewable fuel with assigned RINs will simply retain an inventory of 
all assigned RINs owned. As volumes of renewable fuel are then 
transferred to other parties, an appropriate number of gallon-RINs are 
withdrawn from the party's inventory and transferred along with the 
renewable fuel. There is no need for the party to determine which RINs 
were originally assigned to the volume being transferred. For parties 
handling both ethanol and biodiesel, it would be reasonable to transfer 
RINs with volumes in a manner consistent with the Equivalence Value of 
the renewable fuel, but this would not be required under our final 
regulations in which the number of assigned gallon-RINs transferred 
with each gallon of renewable fuel can be anywhere between zero and 
2.5. In addition, volumes of renewable fuel can be split or merged any 
number of times while remaining under the ownership of a single party, 
with no impact on RINs. It is only when ownership of a volume of 
renewable is transferred to another party that an appropriate number of 
gallon-RINs need to be withdrawn from the party's inventory and 
assigned to the transferred volume, subject to the flexibility 
associated with the quarterly average as discussed above.
2. Separation of RINs From Volumes of Renewable Fuel
    Separation of a RIN from a volume of renewable fuel means that the 
RIN is no longer included on the PTD and can be traded independently 
from the volume to which it had originally been assigned. In general 
commenters supported our proposed approach of limiting the parties that 
can separate a RIN from a batch, and the associated conditions under 
which separation can occur.
    In designing the regulatory program, we structured it around 
facilitating compliance by obligated parties with their renewable fuel 
obligation, with the intention of giving obligated parties the power to 
market the renewable fuel separately from the RIN originally assigned 
to it. Our final program therefore requires a refiner or importer to 
separate the RIN from renewable fuel as soon as he assumes ownership of 
that renewable fuel. In the case of ethanol blended into gasoline at 
low concentrations (< = 10 volume percent), stakeholders have informed 
us that a large volume of the ethanol is purchased by refiners directly 
from ethanol producers, and is then passed to blenders who carry out 
the blending with gasoline. Therefore, in many cases RINs assigned to 
renewable fuel will pass directly from the producers who generated them 
to the obligated parties who need them.
    However, significant volumes of ethanol are also blended into 
gasoline without first being purchased by a refiner. In some cases, the 
blender itself purchases the ethanol. In other cases, a downstream 
customer purchases the ethanol and contracts with the blender to carry 
out the blending. Regardless, the ethanol may never be held or owned by 
an obligated party before it is blended into gasoline. Thus we are also 
requiring a blender to separate the RIN from the renewable fuel if he 
takes ownership of the renewable fuel and actually blends it into 
gasoline (or, in the case of biodiesel, into diesel fuel). This would 
only apply to volumes where the RIN had not already been separated by 
an obligated party. Since blenders will in general not be obligated 
parties under our program, blenders who separate RINs from renewable 
fuel will have no need to hold onto those RINs and thus can transfer 
them to an obligated party for compliance purposes or to any other 
party.
    There may be occasions in which a retailer downstream of a blender 
actually owns the volume of renewable fuel when it is blended into 
gasoline or diesel. In such cases the blender will have custody but not 
ownership of the renewable fuel. In today's final rule we are requiring 
the RIN to be separated from the volume of renewable fuel when that 
volume is blended into gasoline, but the RIN can only be separated by 
the party that owns that volume of renewable fuel at the time of 
blending. In the case of a blender and a downstream customer who might 
both lay claim to the right to separate any assigned RINs (for 
instance, if transfer of ownership occurred simultaneous with 
blending), these two parties would need to come to agreement between 
themselves regarding which party will own the separated RINs.
    As described in Section III.B, many different types of renewable 
fuel can be used to meet the RFS volume obligations placed upon 
refineries and importers. Currently, ethanol is the most prominent 
renewable fuel and is most commonly used as a low level blend in 
gasoline at concentrations of 10 volume percent or less. However, some 
renewable fuels can be used in neat form (i.e. not blended with 
conventional gasoline or diesel). The two RIN separation situations 
described above would capture any renewable fuel for which ownership is 
assumed by an obligated party or a party that blends the renewable fuel 
into gasoline or diesel. However, renewable fuels which are used in 
their neat (unblended) form as motor vehicle fuel would not be 
captured. This would include such renewable fuels as neat biodiesel 
(B100) or renewable diesel, methanol for use in a dedicated methanol 
vehicle or biogas for use in a CNG vehicle.
    Under our final program, producers and importers must assign a RIN 
to all renewable fuels produced or imported, including neat renewable 
fuels. To avoid the possibility that the RIN assigned to neat renewable 
fuel would never become available to an obligated

[[Page 23943]]

party for RFS compliance purposes, in the NPRM we proposed to more 
broadly define the right to separate a RIN from renewable fuel. In 
addition to obligated parties and blenders, we proposed that any 
producer holding a volume of renewable fuel for which the RIN has not 
been separated could separate the RIN from that volume if the party 
designates it for use only as a motor vehicle fuel in its neat form and 
it is in fact only used as such. This approach would recognize that the 
neat form of the renewable fuel is valid for compliance purposes under 
the RFS program, as described in Section III.B. In effect, it would 
place neat fuel producers in the same category as blenders, in that 
they are producing motor vehicle fuel. We did not receive any negative 
comments on this proposal, and thus are finalizing this provision as 
proposed.
    As discussed above, under our final rule, obligated parties must 
separate RINs from volumes of renewable fuel. This applies to all 
volumes of renewable fuel that an obligated party owns. The requirement 
to separate a RIN from the renewable fuel is intended to apply to 
refiners, blenders and importers for whom the production or importation 
of gasoline is a significant part of their overall business operations. 
Parties that are predominately renewable fuel producers or importers, 
but which must be designated as obligated parties due to the production 
or importation of a small amount of gasoline, should not be able to 
separate RINs from all renewable fuels that they own. For example, we 
believe it would be inappropriate to permit an ethanol producer to 
separate RINs from all volumes that they own simply because the 
producer imported, for example, a single truckload of gasoline from 
Canada or Mexico. As a result, the final rule prohibits obligated 
parties from separating RINs from volumes of renewable fuel that they 
produce or import that are in excess of their RVO. However, obligated 
parties must separate any RINs from volumes of renewable fuel that they 
own if that volume was produced or imported by another party.
    As described in Section III.B.2, RINs can be generated for 
renewable fuels made from renewable crude which is treated as if it 
were a petroleum-derived crude oil or derivative, and is used as a 
feedstock in a traditional refinery processing unit. Whether the 
renewable crude is coprocessed with petroleum derivatives or is 
processed in a facility or unit dedicated to the renewable crude, the 
final product is generally a motor vehicle fuel. In such cases the 
refinery will have the responsibility of generating RINs for the 
renewable fuel produced. But since renewable crude is generally 
processed in a traditional refinery, the refiner will be an obligated 
party and can therefore immediately separate those RINs from the 
renewable fuel and transfer them to another party. As described in 
III.E.1.a above, cellulosic and waste-derived ethanol producers will 
also be permitted to separate the RINs associated with the extra 1.5 
value of their ethanol production.
    Once a RIN is separated from a volume of renewable fuel, the PTD 
associated with that volume can no longer list the RIN. However, in the 
NPRM we requested comment on whether PTDs should include some notation 
indicating that the assigned RIN has been removed to avoid concerns 
about whether RINs assigned to batches have not been appropriately 
transferred with the batch. One refiner commented that the addition of 
such a note on a PTD would represent an unnecessary burden, while two 
commenters representing fuel distribution operations indicated that 
such a notation would be useful. Based on comments we received, we have 
determined that such notation on PTDs would not only be useful to 
parties receiving volumes of renewable fuel, but would also be an 
important element of our RIN distribution requirements under our 
modified approach. The requirement will ensure that parties who take 
ownership of renewable fuel without assigned RINs will know that RINs 
were originally assigned but subsequently removed. We also believe that 
such a requirement would be of minimal burden to parties that have 
separated a RIN from a volume of renewable fuel.
    As described in Section III.E.1.b, we have modified the RIN 
transfer requirements for the final rule to make RINs more fungible and 
to provide more flexibility to distributors while still requiring RINs 
to be transferred with volumes of renewable fuel. However, our modified 
approach requires that we distinguish between RINs assigned to 
renewable fuel and RINs that have already been separated from renewable 
fuel. Our final rule thus requires that parties who separate a RIN from 
renewable fuel must change the K code for that RIN to a value of 2. The 
RIN then becomes an unassigned RIN that can be transferred independent 
of renewable fuel volumes.
    In the NPRM we also provided a discussion of the unique 
circumstances regarding biodiesel (mono alkyl esters) \40\ and the 
conditions under which we believed a RIN should be separated from a 
volume of such biodiesel. As described in the proposal, biodiesel is 
one type of renewable fuel that can under certain conditions be used in 
its neat form. However, in the vast majority of cases it is blended 
with conventional diesel fuel before use, typically in concentrations 
of 20 volume percent or less. This approach is taken for a variety of 
reasons, such as to reduce impacts on fuel economy, to mitigate cold 
temperature operability issues, to address concerns of some engine 
owners or manufacturers regarding the impacts of biodiesel on engine 
durability or drivability, or to reduce the cost of the resulting fuel. 
Biodiesel (mono alkyl esters) is also used in low concentrations as a 
lubricity additive and as a means for complying with the ultra-low 
sulfur requirements for highway diesel fuel. Biodiesel (mono alkyl 
esters) is occasionally used in its neat form. However, this approach 
is the exception rather than the rule. Consequently, in the NPRM we 
proposed that the RIN assigned to a volume of biodiesel could only be 
separated from that volume if and when the biodiesel was blended with 
conventional diesel. To avoid claims that very high concentrations of 
biodiesel count as a blended product, we also proposed that biodiesel 
must be blended into conventional diesel at a concentration of 80 
volume percent or less before the RIN could be separated from the 
volume.
---------------------------------------------------------------------------

    \40\ Throughout this Section III.E.2, ``biodiesel'' means mono 
alkyl esters, not non-ester renewable diesel.
---------------------------------------------------------------------------

    A number of commenters expressed concern that the 80 volume percent 
limit put biodiesel at odds with the RIN separation criteria applicable 
to other renewable fuels, including neat fuels. Upon further 
consideration, we have determined that the 80 volume percent limit 
remains a valid means for ensuring that the separation of RINs from 
biodiesel is consistent with its common use at low blend levels just as 
for ethanol, and that RINs are generally separated at the point in time 
when the biodiesel can be deemed to be motor vehicle fuel. However, 
based on comments received, we are changing the treatment of biodiesel 
for the final rule in two ways.
    First, obligated parties are required to separate RINs from volumes 
of biodiesel at the point when they gain ownership of the biodiesel, 
not when they blend biodiesel with conventional diesel fuel. This 
approach is consistent with our treatment of the RIN separation

[[Page 23944]]

requirements for obligated parties for other renewable fuels. Parties 
that actually blend biodiesel into conventional diesel fuel at a 
concentration of 80 volume percent or less would continue to be 
required to separate the RIN from the biodiesel, as proposed.
    Second, we have determined that a biodiesel producer should be 
allowed to separate a RIN from a volume of biodiesel that it produces 
if it designates the volume of biodiesel specifically for use as motor 
vehicle fuel in its neat form, and the neat biodiesel is in fact used 
as motor vehicle fuel. In general this demonstration would require that 
the producer track the volume of biodiesel to the point of its final 
use. However, this approach to the treatment of neat biodiesel is 
consistent with how we are treating other renewable fuels used in their 
neat form.
3. Distribution of Separated RINs
    In the NPRM, we proposed that RINs become freely transferable once 
they are separated from a batch of renewable fuel. Each RIN could be 
held by any party and transferred between parties any number of times. 
We argued that the unique features of the RFS program warranted more 
open trading than in past fuel credit programs. In particular, RINs are 
generated by parties other than obligated parties, and many 
nonobligated parties will own RINs (for example, oxygenate blenders who 
have the right to separate RINs from volumes). While recognizing that 
limiting trading to and between obligated parties might help obligated 
parties to maintain control of those RINs being traded, such an 
approach could have the unintended effect of limiting the number of 
RINs that non-obligated parties contribute to the RIN market. The RFS 
program must work efficiently not only for a limited number of 
obligated parties, but a number of non-obligated parties as well.
    There was disagreement among commenters about whether an open RIN 
market was appropriate. Several parties supported our proposed 
approach, saying that unlimited trading among all interested parties 
would increase liquidity and transparency in the RIN market. They also 
argued that increasing the number of participants would facilitate the 
acquisition of RINs by obligated parties and promote economic 
efficiency.
    However, some commenters disagreed, arguing instead that an open 
market does not necessarily make the market any more fluid and free. 
They pointed to past credit programs in which only refiners and 
importers have been allowed to transfer credits, and argued that the 
success of those programs should compel the Agency to use those past 
credit program structures as the model for the RFS program.
    We continue to believe that there is a need to provide for more 
open trading in the RFS program and that this need warrants a unique 
approach for this rule. First, unlike other programs where credits 
generally represent overcompliance with an applicable standard and are 
thus supplemental to the means of compliance, under the RFS program 
RINs are the fundamental unit for compliance. There will be many more 
RINs in the RFS program than credits in other programs, and the trading 
structure must maximize the fluidity of those RINs. A wider RIN market 
will make it easier for obligated parties to get access to RINs.
    Second, obligated parties are typically not the ones producing the 
renewable fuels and generating the RINs, nor blending the renewable 
fuels into gasoline, so there is a need for trades to occur between 
obligated parties and non-obligated parties. If we prohibited everyone 
except obligated parties from holding RINs after they have been 
separated from a batch, non-obligated parties seeking avenues for 
releasing their RINs would only be able to release them to obligated 
parties. Having fewer avenues through which they could market their 
RINs, some non-obligated parties might opt not to transfer their RINs 
at all rather than participate in the RIN market with the attendant 
recordkeeping requirements. Furthermore, a potentially large number of 
oxygenate blenders, many of which will be small businesses, will be 
looking for ways to market their RINs. Allowing other parties, 
including brokers, to own and transfer RINs may create a more fluid and 
free market that would increase the venues for RINs to be acquired by 
the obligated parties that need them. Limiting RIN trading to and among 
obligated parties could make it more difficult for RINs to eventually 
be transferred to the obligated parties that need them.
    Some commenters argued that limiting the RIN trading market to and 
among obligated parties would make the program more enforceable, since 
there would be fewer parties to track and the sources of RINs would be 
more reliable. While this may be directionally true, we believe the RFS 
program will remain sufficiently enforceable under an open RIN market, 
and as discussed above, the greater need for market fluidity for this 
program warrants the change. The RIN number, along with the associated 
electronic reporting mechanism, will provide us the ability to verify 
the validity of RINs and the source of any invalid RINs. Since all RINs 
generated, traded, and used for compliance would be recorded 
electronically in an Agency database, these types of investigations 
should be straightforward. The number of RIN trades, and the parties 
between whom the RINs are being traded, will only have the effect of 
increasing the size of the database.
    Some commenters were concerned that an open RIN market could lead 
to price volatility and potentially higher prices as non-obligated 
speculators enter the market expressly to profit from the sale of RINs. 
According to commenters, these speculators would hold an unfair 
advantage over obligated parties that must purchase credits for 
compliance since speculators can hold onto RINs indefinitely, driving 
up their price. However, by expanding the number of parties that can 
hold RINs, we minimize the potential for any one party to exercise 
market power, and thus we do not believe that such activity on the part 
of speculators is likely to substantively affect the availability of 
RINs or their price. Moreover, we do not believe that a given party 
will hold a RIN indefinitely simply to increase profit because RINs 
have a limited life and new RINs will be generated and will enter the 
market continuously.
    Based on our review of the comments received, we did not find 
compelling evidence that an open market for RINs would create 
particular difficulties for obligated parties seeking RINs or would 
limit the enforceability of the program. As a result we are finalizing 
a RIN trading program that permits any party to hold RINs and for RINs 
to be traded any number of times.
    As with other credit-trading programs, the business details of RIN 
transactions, such as the conditions of a sale or any other transfer, 
RIN price, role of mediators, etc. will be at the discretion of the 
parties involved. The Agency is concerned only with information such as 
who holds a given RIN at any given moment, when transfers of RINs 
occur, who the party to the transfers are, and ultimately which 
obligated party relies on a given RIN for compliance purposes. This 
type of information will therefore be the subject of various 
recordkeeping and reporting requirements as described in Section IV, 
and these requirements will generally apply regardless of whether a RIN 
has been separated from a batch.
    The means through which RIN trades occur will also be at the 
discretion of the parties involved. For instance, parties with RINs can 
create open auctions, contract directly with those

[[Page 23945]]

obligated parties who seek RINs, use brokers to identify potential 
transferees and negotiate terms, or just transfer the RINs to any other 
party. Brokers involved in RIN transfer can either operate in the role 
of arbitrator without owning the RINs, or alternatively can take 
custody of the RINs from one party and transfer them to another. If 
they are the transferee of any RINs, they will also be subject to the 
registration, recordkeeping, and reporting requirements. The Agency 
will not be directly involved in RIN transfers, other than in the role 
of providing a database within which transfers will be recorded for 
enforcement purposes.
    In order to provide public information that could be helpful in 
managing and trading RINs as well as understanding how the program is 
operating, we intend to publish a report each year that summarizes 
information submitted to us through the quarterly and annual reports 
required as part of our enforcement efforts (see Section IV). Annual 
summary reports published by EPA may include such information as the 
number of RINs generated in each month or in each state, the average 
number of trades that RINs undergo before being used for compliance 
purposes, or the frequency of deficit carryovers. However, we will not 
publish information identifying specific parties.
4. Alternative Approaches to RIN Distribution
    In the NPRM, we also described several alternative approaches to 
the proposed trading and compliance program that were offered by 
stakeholders. Most of these alternatives recognized the value of a RIN-
based system of compliance, but they differed in terms of which parties 
would be allowed to separate a RIN from a batch and the means through 
which the RINs would be transferred to obligated parties. We invited 
comment on all of these alternatives in the NPRM, but received very 
few. Based on those comments we did receive, we do not believe that any 
of these alternative approaches should be implemented at this time. In 
general our responses to comments on the alternatives can be found in 
the Summary and Analysis of Comments document in the docket, but we 
have addressed one particular subject area below.
    In the NPRM, we described an alternative approach to RIN 
distribution in which obligated parties would only be able to separate 
a RIN from a batch of renewable fuel at the point in time when blending 
actually occurs. In contrast, the approach we are finalizing today 
requires an obligated party to separate a RIN from a batch as soon as 
it gains ownership of that batch. Our final program design is based on 
the expectation that all but a negligible quantity of renewable fuels 
will eventually be consumed as motor vehicle fuel, primarily through 
blending with gasoline or diesel. See further discussion in Section 
III.D. As a result, we do not believe that it is necessary to verify 
that blending has actually occurred in order to provide a program that 
adequately ensures it occurs. The American Petroleum Institute agreed 
that tracking renewable fuels to the point of blending would represent 
an unnecessary burden and added that such a requirement could preclude 
many obligated parties from taking direct steps to obtain RINs to meet 
their obligations.
    The Renewable Fuels Association, however, argued that allowing 
obligated parties to separate RINs from batches before blending 
occurred could give rise to RIN hoarding, fraud, and confusion. Most 
importantly, they noted, the alternative approach would provide direct 
verification of blending. For the reasons described in Section III.D, 
we do not believe that a compliance system requiring verification of 
blending is necessary, given that, with the exception of exports, 
essentially all renewable fuel produced in the U.S. is used as motor 
vehicle fuel in the U.S. This is a foundational principle of the use of 
a RIN-based program design that enjoyed widespread support among 
stakeholders and widespread recognition that it accurately describes 
real world practices.
    If verification of blending were required before a RIN could be 
separated from a batch, both obligated parties and blenders would be 
subject to additional recordkeeping and paperwork burdens. The Agency 
would be compelled to enforce activities at the blender level, adding 
about 1200 parties to the list of those subject to enforcement under 
our final program. Although we agree that the reformulated gasoline 
program could act as a model from which to construct such a 
recordkeeping and enforcement system, we continue to believe that such 
a system would be both unnecessary and burdensome.
    The Renewable Fuels Association also argued that our proposed 
program would result in confusion in the distribution system, since 
there would be renewable fuel both with and without RINs. However, 
there are many other reasons that this situation could arise, and none 
is expected to negatively impact the distribution of renewable fuels or 
the business agreements developed by parties transferring renewable 
fuels. For instance, we are exempting small volume producers from 
generating RINs, renewable fuels with equivalence values less than 1.0 
may have fewer RINs than gallons, and volume swell and metering 
discrepancies can all contribute to situations in which batches 
legitimately do not have assigned RINs corresponding to their actual 
volumes. Parties that sell such batches could choose to price such 
product differently from product that has assigned RINs with a one-to-
one correspondence to product volume. We are also requiring that PTDs 
associated with transfers of volume include notation indicating whether 
RINs are being simultaneously transferred to address these types of 
situations.
    Another commenter argued that the alternative approach could limit 
the potential for one refiner to purchase large volumes of renewable 
fuel with the intent of separating the RINs and exercising market power 
in the RIN market. However, the commenter did not provide any 
information regarding how such market power could be exercised by one 
refiner in a system where unassigned RINs can be transferred freely 
between parties any number of times, and access to those RINs is not 
limited geographically in any way. In addition, RINs that have been 
separated from their assigned batches by oxygenate blenders represent 
an additional safety valve in the RIN market, providing additional 
assurances that no one refiner could exercise market power in the RIN 
market.
    Commenters supporting a requirement that RINs be separated only at 
the point of blending offered no other arguments that hoarding or fraud 
could actually occur under our proposed approach. Therefore, we are 
finalizing an approach that requires obligated parties to separate RINs 
from batches at the point of ownership.

IV. Registration, Recordkeeping, and Reporting Requirements

A. Introduction

    Registration, recordkeeping and reporting are necessary to track 
compliance with the renewable fuels standard and transactions involving 
RINs. This summarizes these requirements. Our estimates as to the 
burden associated with registration, recordkeeping and reporting are 
contained in this Federal Register notice in Section XII.B and 
explained fully in ``OMB-83 Supporting Statement--Renewable Fuels 
Standard

[[Page 23946]]

(RFS) Program (Final Rule)--EPA ICR No. 2242.02,'' which has been 
placed in the public docket for this rulemaking.

B. Registration

1. Who Must Register Under the RFS Program?
    Obligated parties (including refiners and importers), exporters of 
renewable fuels, producers and importers of renewable fuels, and any 
party who owns RINs must register with EPA. Any party may own RINs 
including, but not limited to, the above-named parties and marketers, 
blenders, terminal operators, jobbers, and brokers. Owning RINs, and 
engaging in any activities regarding RINs, is prohibited as of 
September 1, 2007 unless the party has registered and received EPA 
company and facility identification numbers.
    Most refiners and importers and many biodiesel producers are 
already registered with us under various regulations in 40 CFR part 80 
related to reformulated (RFG) and conventional gasoline or diesel fuel. 
Parties who are already registered will not have to take any action to 
register under the RFS program, because their existing registration 
will be applied to the RFS program as well.
2. How Do I Register?
    Registration is a simple process. We will use the same basic forms 
for RFS program registration that we use under the reformulated 
gasoline (RFG) and anti-dumping program. You may download our 
registration forms at http://www.epa.gov/otaq/regs/fuels/rfgforms.htm. 

These forms are well known in the regulated community and are very 
simple to fill out. Information requested includes company and facility 
names, addresses, and the identification of a contact person with 
telephone number and e-mail address. Registrations never expire and do 
not have to be renewed. However, all registered parties are responsible 
for notifying us of any change to their company or facility 
information.
3. How Do I Know I Am Properly Registered With EPA?
    Upon receipt of a completed registration form, we will provide you 
with a unique 4-digit company identification number and a unique 5-
digit facility identification number. These numbers will appear in 
compliance reports and, in the case of renewable fuel producers and 
importers, they will be incorporated in the unique RINs they generate 
for each batch of renewable fuel. Timely registration is important 
because you cannot generate or handle transactions involving RINs until 
you have registered and received your registration numbers from us. It 
is advisable to register as soon as possible if you believe you will be 
engaged in activities that may require registration under the RFS 
program. Registration can occur any time following signature of this 
final rule.
    If you are already registered under another fuels program, such as 
RFG and anti-dumping or diesel sulfur, then you do not have to register 
again. You will use the same company and facility identification number 
you are currently using for RFS reporting. Parties in this situation 
may contact the Agency for confirmation or clarification of the 
appropriate registration numbers to use. As noted above, registrations 
never expire, but you are responsible for keeping the information we 
have up to date. If you have previously registered with us but have not 
had to report until now, then you may wish to contact the person listed 
on our renewable fuels Web page (http://www.epa.gov/otaq/renewablefuels/index.htm
) in order to confirm the information in your 

registration file.
4. How Are Small Volume Domestic Producers of Renewable Fuels Treated 
for Registration Purposes?
    Small volume domestic producers of renewable fuels are those who 
produce less than 10,000 gallons per year or who import less than 
10,000 gallons per year. These parties are not required to register if 
they do not wish to generate RINs. If a small volume domestic producer 
of renewable fuels wishes to generate RINs, then that party must 
register and comply with all recordkeeping and reporting requirements.

C. Reporting

1. Who Must Report Under the RFS Program?
    Obligated parties, exporters of renewable fuel, producers and 
importers of renewable fuel, and any party who owns either assigned or 
unassigned RINs such as marketers or brokers must submit periodic 
reports to us covering RIN generation, RIN use, and RIN transactions.
2. What Reports Are Required Under the RFS Program?
    There are four basic reports under the RFS program. The first 
report is an annual compliance demonstration report that is required to 
be submitted by obligated parties and exporters of renewable fuel. This 
report provides the RFS compliance demonstration and is required to be 
submitted on an annual basis. It is focused on calculating the RVO, 
indicating RINs used for compliance, and determining any deficit 
carried over.
    The second report is a quarterly RIN generation report that is 
required to be submitted by producers and importers of renewable fuel. 
This report is focused on providing information on all batches of 
renewable fuel produced and imported and all RINs generated.
    The third report is a RIN transaction report that is required to be 
submitted by any party that owns RINs, including RIN marketers and 
brokers, as well as obligated parties, exporters, and renewable fuel 
producers and importers. This report is focused on providing 
information on individual RIN purchases, RIN sales, retired RINs, and 
expired RINs.\41\ A separate RIN transaction report is required to be 
submitted for each RIN purchase and sale, and for each retired or 
expired RIN, and must be submitted by the end of the quarter in which 
the activity occurred. The purpose of the RIN transaction report is to 
document the ownership and transfer of RINs, and to track expired and 
retired RINs. This report is necessary because compliance with the RVO 
is primarily demonstrated through self-reporting of RIN trades and 
therefore we must be able to link transactions involving each unique 
RIN in order to verify compliance. We will be able to import reports 
into our compliance database and match RINs to transactions across 
their entire journey from generation to use. As with our other 40 CFR 
part 80 compliance-on-average and credit trading programs, many 
potential violations are expected to be self-reported.
---------------------------------------------------------------------------

    \41\ In this final rule, we have clearly distinguished expired 
RINs, which are no longer valid due to the passage of time, from 
retired RINs, which are RINs no longer valid due to the reportable 
spillage of their assigned volumes under Sec.  80.1132, RINs used to 
satisfy an enforcement action, or RINs used to effect an import 
volume correction under Sec.  80.1166(k). Rather than leaving 
retired RINs under ``any additional information that the 
Administrator may require,'' we have specifically addressed them in 
this final rule. We believe it is useful to specifically distinguish 
between retired and expired RINs because it will be easier for us to 
determine whether a report is complete and to quality assure and 
check reported information by applying a consistent reporting 
distinction between expired and retired RINs.
---------------------------------------------------------------------------

    The fourth report is a quarterly gallon-RIN activity report that 
also is required to be submitted by any party that owns RINs. This 
report is focused on the total number of gallon-RINs owned at the start 
and end of the quarter, and the total number of gallon-RINs purchased, 
sold, retired and expired during the quarter. This report also requires

[[Page 23947]]

information on end-of-quarter renewable fuel volumes.
3. What Are the Specific Reporting Items for the Various Types of 
Parties Required To Report?
    The following table summarizes the information to be submitted in 
each type of report by the type of regulated party:

                     Table IV.C.3-1.--Information Contained in Reports by Regulated Party *
----------------------------------------------------------------------------------------------------------------
                                                                             Producers and
         Type of report            Obligated parties     Exporters of        importers of      Other parties who
                                                        renewable fuel      renewable fuel         own RINS
----------------------------------------------------------------------------------------------------------------
Annual Compliance Demonstration                           No report.........  No report.
 Report.                           Calculation of      Calculation of
                                   RVO.                RVO.
                                   List of     List of
                                   RINs used for       RINS used for
                                   compliance.         compliance.
                                              
                                   Calculation of      Calculation of
                                   deficit carryover.  deficit carryover.
Quarterly RIN Generation Report.  No report.........  No report.........   Volume of  No report.
                                                                           each batch
                                                                           produced or
                                                                           imported.
                                                                           RINs
                                                                           generated for
                                                                           each batch.
                                                                           Volume of
                                                                           denaturant and
                                                                           applicable
                                                                           equivalence value
                                                                           of each batch.
RIN Transaction Report..........  Separate report     Separate report     Separate report     Separate report
                                   for each            for each            for each            for each
                                   transaction:.       transaction:.       transaction:.       transaction:
                                   RIN         RIN         RIN         RIN
                                   purchase.           purchase.           purchase.           purchase.
                                   RIN sale.   RIN sale.   RIN sale.   RIN sale.
                                   Expired     Expired     Expired     Expired
                                   RIN.                RIN.                RIN.                RIN.
                                   Retired     Retired     Retired     Retired
                                   RIN.                RIN.                RIN.                RIN.
Quarterly gallon-RIN Activity      Number of   Number of   Number of   Number of
 Report.                           gallon-RINs*        gallon-RINs owned   gallon-RINs owned   gallon-RINs owned
                                   owned at start of   at start of         at start of         at start of
                                   quarter.            quarter.            quarter.            quarter.
                                   Number of   Number of   Number of   Number of
                                   gallon-RINs         gallon-RINs         gallon-RINs         gallon-RINs
                                   purchased.          purchased.          purchased.          purchased.
                                   Number of   Number of   Number of   Number of
                                   gallon-RINs sold.   gallon-RINs sold.   gallon-RINs sold.   gallon-RINs sold.
                                   Number of   Number of   Number of   Number of
                                   gallon-RINs         gallon-RINs         gallon-RINs         gallon-RINs
                                   retired.            retired.            retired.            retired.
                                   Number of   Number of   Number of   Number of
                                   gallon-RINs         gallon-RINS         gallon-RINs         gallon-RINs
                                   expired (4th        expired (4th        expired (4th        expired (4th
                                   quarter only).      quarter only).      quarter only).      quarter only).
                                   Number of   Number of   Number of   Number of
                                   gallon-RINs at      gallon-RINs at      gallon-RINs at      gallon-RINs at
                                   end of quarter.     end of quarter.     end of quarter.     end of quarter.
                                   Volume      Volume      Volume      Volume
                                   (gals) of           (gals) of           (gals) of           (gals) of
                                   renewable fuel      renewable fuel      renewable fuel      renewable fuel
                                   owned at end of     owned at end of     owned at end of     owned at end of
                                   quarter.            quarter.            quarter.            quarter.
----------------------------------------------------------------------------------------------------------------
* A gallon-RIN is a RIN that represents an individual gallon of renewable fuel. See Sec.   80.1101.

4. What Are the Reporting Deadlines?
    In the proposed rule, we had requested comment on whether reporting 
should be annual or quarterly. After consideration of comments 
received, we have determined that each RIN transaction report must be 
submitted by the end of the quarter in which the transaction occurred, 
and the gallon-RIN activity report should be submitted quarterly. 
Quarterly reporting is better because it provides us with the 
information necessary to confirm the validity and legitimacy of RINs 
prior to their use in compliance. Additionally, quarterly reporting 
enables EPA to enforce the RIN/inventory balance requirements for 
producers and marketers of renewable fuels.
    The annual compliance demonstration for obligated parties must be 
submitted by February 28th for the prior calendar year. For the RIN 
transaction and quarterly gallon-RIN activity reports, the following 
schedule applies to all reporting parties:

      Table IV.C.4-1.--Quarterly Reporting Schedule for RFS Program
------------------------------------------------------------------------
  Quarter covered by  quarterly report    Due date for quarterly report
------------------------------------------------------------------------
January-March..........................  May 31.
April-June.............................  August 31.
July-September.........................  November 30.
October-December.......................  February 28.
------------------------------------------------------------------------

    In the first year of the RFS program only, obligated parties and 
exporters are given an extra quarter to submit their list of RINs used 
to demonstrate compliance. This information must be reported by May 31, 
2008 for calendar year 2007. All other reporting follows the schedule 
indicated above.
5. How May I Submit Reports to EPA?
    We will use a simplified and secure method of reporting via the 
Agency's 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 will eliminate the 
need for wet ink signatures and will reduce the reporting burden on 
regulated parties. Guidance for reporting will be issued before 
implementation and will contain specific instructions and formats 
consistent with provisions in this final rule. The guidance will be 

[[Page 23948]]

http://www.epa.gov/otaq/renewablefuels/index.htm.

    We will accept electronic reports generated in virtually all 
commercially available spreadsheet programs and will even permit 
parties to submit reports in comma delimited text, which can be 
generated with a variety of basic software packages.
    CDX will confirm delivery of your report. As described below with 
regard to recordkeeping, you must retain copies of all items submitted 
to us for five (5) years.
6. What Does EPA Do With the Reports it Receives?
    In order to permit maximum flexibility in meeting the RFS program 
requirements, we must track activities involving the creation and use 
of RINs, as well as any transactions such as purchase or sale of RINs. 
Reports will be imported into a compliance database managed by EPA's 
Office of Transportation and Air Quality and will be reviewed for 
completeness and for potential violations. It is important to keep your 
company contact updated (this is an item on the registration form), 
because we may need to speak to that person about any problems with a 
report submitted. Potential violations will be referred to EPA 
enforcement personnel.
7. May I Claim Information in Reports as CBI and How Will EPA Protect 
it?
    You may claim information submitted to us as confidential business 
information (CBI). Please be sure to follow all reporting guidance and 
clearly mark the information you claim as proprietary. We will treat 
information covered by such a claim in accordance with the regulations 
at 40 CFR part 2 and other Agency procedures for handling proprietary 
information.
8. How Are Spilled Volumes With Associated Lost RINs To Be Handled in 
Reports?
    Since spills can happen whenever renewable fuel with assigned RINs 
is held, owners have two options if the spill causes their organization 
to be out of compliance. The owners of the spilled fuel may either 
retire RINs lost in reported spills or purchase and sell a volume of 
renewable fuel equal to the reported volume and not associated with 
RINs in order to meet compliance. Reportable spills for the purposes of 
this rule refers to spills of renewable fuel with assigned RINs and a 
requirement by a federal, state, or local authority to report said 
spills. The party that owns the spilled renewable fuel must retire a 
number of gallon-RINs corresponding to the volume of spilled renewable 
fuel multiplied by its equivalence value. If the equivalence value for 
the spilled volume may be determined based on its composition, then the 
appropriate equivalence value shall be used. If the equivalence value 
for the spilled volume cannot be determined, the equivalence value is 
1.0. In the case that the fuel must be reported in pounds rather than 
gallons, the party that reported the spill should use the best 
available conversion for converting the volume into gallons. In the 
event that volume is spilled in transport, the owner of the RINs will 
need to request a copy of the spill report from the party that reported 
the spill.

D. Recordkeeping

1. What Types of Records Must Be Kept?
    The recordkeeping requirements for obligated parties and exporters 
of renewable fuels support the enforcement of the use of RINs for 
compliance purposes. Records kept by parties are central to tracking 
individual RINs through the fungible distribution system after those 
RINs are assigned to batches of renewable fuel. Parties use invoices or 
other types of product transfer documentation, which are customarily 
generated and issued in the course of business and which are familiar 
to parties who transfer or receive fuel. Parties are afforded 
significant freedom with regard to the form these documents take, 
although they must travel in some manner (on paper or electronically) 
with the volume of renewable fuel being transferred. On each occasion 
any person transfers ownership of renewable fuels subject to this 
regulation, that transferor must provide the transferee with documents 
identifying the renewable fuel and containing the identifying 
information that includes: The name and address of the transferor and 
transferee, the EPA-issued company identification number of the 
transferor and transferee, the volume of renewable fuel that is being 
transferred, the date of transfer, and each associated RIN. These types 
of documents must be used by all parties in the distribution chain down 
to the point where the renewable fuel is blended into conventional 
gasoline or diesel.
    Except for transfers to truck carriers, retailers or wholesale 
purchaser-consumers, product codes may be used to convey the 
information required, as long as the codes are clearly understood by 
each transferee. However, the RIN must always appear in its entirety 
before it is separated from a batch, since it is a unique 
identification number that cannot be summarized by a shorter code.
    Parties must keep copies of all records for a period of not less 
than five (5) years. In addition to documentation related to transfers, 
parties must keep information related to the sale, purchase, brokering 
and trading of RINs and copies of any reports they submit to us for 
compliance reports. For example, if a volume of fuel and its associated 
RINs are reported to us as lost due to spillage, documentation related 
to that spill must be retained for the five year period. Upon request, 
parties are responsible for providing records to the Administrator or 
the Administrator's authorized representative.
2. What Recordkeeping Requirements Are Specific to Producers of 
Cellulosic or Waste-Derived Ethanol?
    In addition to the records applicable to all ethanol producers, 
producers of cellulosic biomass or waste-derived ethanol must keep 
records of fuel use in order to ensure compliance with, and enforcement 
of, the definitions of these types of renewable fuel. Producers of 
cellulosic biomass or waste-derived ethanol must keep records of volume 
and types of all feedstocks purchased to ensure compliance with, and 
enforcement of, the feedstock aspect of the definitions of cellulosic 
biomass and waste-derived ethanol. In addition, producers of cellulosic 
biomass or waste-derived ethanol are required to arrange for an 
independent third party to review the ethanol producer's records and 
verify that the facility is, in fact, a cellulosic biomass or waste-
derived ethanol production facility and that the ethanol producer is 
producing cellulosic biomass or waste-derived ethanol. The independent 
third party must be a licensed Professional Engineer (P.E.) in the 
chemical engineering field. Domestic ethanol producers are not required 
obtain prior approval of the independent third party P.E. or submit the 
engineering verification to EPA, however, the ethanol producer and the 
P.E. are required to keep records related to the required engineering 
verification and to produce them upon request of the Administrator or 
the Administrator's authorized representative.
    A foreign ethanol producer may apply to us to have its cellulosic 
biomass or waste-derived ethanol treated in the same manner as domestic 
cellulosic biomass or waste-derived ethanol under the RFS program. A 
foreign ethanol producer with an approved application will be required 
to comply with all of the requirements that apply to domestic ethanol 
producers, including registration, recordkeeping, reporting,


[[Continued on page 23949]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 23949-23998]] Regulation of Fuels and Fuel Additives: Renewable Fuel Standard 
Program

[[Continued from page 23948]]

[[Page 23949]]

attest engagements, and the independent third party verification 
discussed above. The attest engagements for a foreign ethanol producer 
must be conducted by a U.S. auditor (if not a U.S. based auditor, the 
auditor must be approved in advance by EPA). Similar to other fuels 
programs, the foreign ethanol producer will be required to comply with 
additional requirements designed to ensure that enforcement of the 
regulations at the foreign ethanol facility will not be compromised. 
The independent third party P.E. conducting the facility verification 
must be approved by EPA before the foreign entity will be allowed to 
treat its cellulosic biomass or waste-derived ethanol in the same 
manner as domestic producers. The foreign ethanol producer must arrange 
for the P.E. to inspect the facility and submit a report to us which 
describes the physical plant and its operation and includes 
documentation of the P.E.'s qualifications. The foreign ethanol 
producer must agree to provide access to EPA personnel for the purposes 
of conducting inspections and audits, post a bond, and arrange for an 
independent inspector to monitor ship loading and offloading records to 
ensure that volumes of ethanol do not change from port of shipping to 
port of entry. The independent inspector must be approved by EPA prior 
to the shipment of any ethanol designated by the foreign ethanol 
producer as ethanol which is to be treated as cellulosic biomass or 
waste-derived ethanol. Cellulosic biomass or waste-derived ethanol 
produced by a foreign ethanol producer must be identified as such on 
product transfer documents that accompany the ethanol to the importer. 
(These additional provisions for foreign ethanol producers are 
contained in Sec.  80.1166.)
    The provisions for foreign ethanol producers are optional and are 
available only to foreign producers of cellulosic biomass or waste-
derived ethanol. Ethanol or other renewable fuels produced and exported 
to the United States by other foreign producers are regulated through 
the importer. An importer that receives ethanol identified as 
cellulosic biomass or waste-derived ethanol produced by a foreign 
producer with an approved application would not assign RINs to the 
ethanol, as RINs for such ethanol will be assigned by the foreign 
ethanol producer. The importer, like any other marketer, would transfer 
the RINs assigned by the foreign producer with a volume of ethanol and 
report the transactions to us.

E. Attest Engagements

1. What Are the Attest Engagement Requirements Under the RFS Program?
    Attest engagements are similar to financial audits and consist of 
an independent, professional review of compliance records and reports. 
Similar to other fuels programs, the RFS program requires reporting 
parties to arrange for annual attest engagements to be conducted by an 
auditor that is ``independent'' under the criteria specified in the 
regulations. We believe that the attest engagements provide an 
appropriate and useful tool for verifying the accuracy of the 
information reported to us. Attest engagements are performed in 
accordance with standard procedures and standards established by the 
American Institute of Certified Public Accountants and the Institute of 
Internal Auditors. The attest engagement consists of an outside 
certified public accountant (CPA) or certified independent auditor 
(CIA) following agreed upon procedures to determine whether underlying 
records, reported items, and transactions agree, and issuing a report 
as to their findings. Attest engagements are performed on an annual 
basis.
2. Who Is Subject to the Attest Engagement Requirements for the RFS 
Program?
    Obligated parties, producers, exporters and importers of renewable 
fuel, and any party who own RINs are all subject to the attest 
engagement requirements.
3. How Are the Attest Engagement Requirements in This Final Rule 
Different From Those Proposed?
    We had proposed that obligated parties, exporters, and renewable 
fuels producers be subject to attest engagement requirements. We 
received several comments on this proposal. Some commenters suggested 
that the attest engagements should be required for renewable fuels 
producers and importers, but not for obligated parties. These 
commenters believe that attest engagements are needed for renewable 
fuel producers and importers in order to verify reported production and 
RIN volumes, whereas we can monitor compliance by obligated parties by 
cross-checking their reports regarding RIN transactions and use with 
the reports from other parties. These commenters also believe that the 
information required by obligated parties under the RFS program is not 
such that an attest engagement is needed because the rule does not 
require verification of raw data as with other fuels programs. We have 
considered these comments but continue to believe that the attest 
engagements are an appropriate means of verifying the accuracy of the 
information reported to us by obligated parties. In addition to 
documentation of RIN transactions and use, the reports include 
information on production and import volumes and calculation of the 
party's RFS obligation. We believe that attest engagements are 
necessary in order to verify that the underlying data regarding 
production and import volumes and RFS obligation, as well as the 
underlying data regarding RIN transactions and use, support the 
information included in the reports. As a result, the final rule 
includes an attest engagement requirement for obligated parties.
    We also received several comments that the attest engagement 
auditor should be required to examine only representative samples of 
the party's RIN transaction documents rather than the documents for 
each RIN transaction, as required in the proposed regulations. We agree 
that examination of representative samples of RIN transaction documents 
would provide sufficient oversight and that the requirement included in 
the proposed regulations may be unnecessarily burdensome. As a result, 
the attest engagement provisions have been modified to require the 
auditor to examine only representative samples of RIN transaction 
documents. However, in the case of attest engagements applied to RIN 
generation by producers or importers of renewable fuel, or the use of 
RINs for compliance purposes by obligated parties or exporters, the 
auditor must examine documentation for all RINs generated or used. We 
believe this requirement is necessary to ensure that obligated parties 
and exporters are meeting their RFS obligation and that ethanol 
producers and importers are assigning RINs to each batch of renewable 
fuel produced or imported as required under the regulations.
    The proposed attest engagement regulations at Sec.  80.1164(b) did 
not include importers of renewable fuels. One commenter pointed out 
these procedures should apply to both renewable fuels producers and 
importers. Renewable fuel importers have the same reporting 
requirements as renewable fuel producers, and, therefore, there is the 
same need for verification of the information given on the reports 
through attest engagements. It was an inadvertent oversight that 
renewable fuel importers were not included in the parties required to

[[Page 23950]]

comply with the attest engagement procedures in proposed Sec.  
80.1164(b), and that applying the requirements in Sec.  80.1164(b) to 
renewable fuel importers is a logical outgrowth of the proposed 
regulations. As a result, the regulations have been modified to include 
renewable fuel importers in the parties required to comply with the 
attest procedures in Sec.  80.1164(b).
    In addition to obligated parties, exporters and renewable fuel 
producers and importers, we believe that an attest engagement 
requirement is necessary for any party who takes ownership of a RIN. As 
discussed above, attest engagements provide an appropriate and useful 
tool for verifying the accuracy of the information reported to us. Like 
obligated parties and renewable fuel producers and importers, the final 
rule requires RIN owners to submit information regarding RIN 
transaction activity to us. We believe that attest engagement audits 
are necessary to verify the accuracy of the information included in 
these reports. Therefore, this final rule includes an attest engagement 
requirement for RIN owners who are not obligated parties or renewable 
fuel producers or importers. We believe that inclusion of the 
requirement in the final rule is a logical outgrowth of the proposed 
attest engagement requirements for other parties who are required to 
submit similar information regarding RIN transaction activity to us.

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

    The prohibition and liability provisions applicable to the RFS 
program are similar to those of other gasoline programs. The final rule 
identifies certain prohibited acts, such as a failure to acquire 
sufficient RINs to meet a party's renewable fuel obligation (RVO), 
producing or importing a renewable fuel without properly assigning a 
RIN, creating, transferring or using invalid RINs, improperly 
transferring renewable fuel volumes without RINs, improperly separating 
RINs from renewable fuel, retaining more RINs during a quarter than the 
party's inventory of renewable fuel, or transferring RINs that are not 
identified by proper RIN numbers. Any person subject to a prohibition 
will be held liable for violating that prohibition. Thus, for example, 
an obligated party will be liable if the party fails to acquire 
sufficient RINs to meet its RVO. A party who produces or imports 
renewable fuels will be liable for a failure to properly assign RINs to 
batches of renewable fuel produced or imported. A renewable fuels 
marketer will be liable for improperly transferring renewable fuel 
volumes without RINs or retaining more RINs during a quarter than the 
party's inventory of renewable fuels. Any party may be liable for 
creating, transferring, or using an invalid RIN, or transferring a RIN 
that is not properly identified.
    In addition, any person who is subject to an affirmative 
requirement under the RFS program will be liable for a failure to 
comply with the requirement. For example, an obligated party will be 
liable for a failure to comply with the annual compliance reporting 
requirements. A renewable fuel producer or importer will be liable for 
a failure to comply with the applicable renewable fuel batch reporting 
requirements. Any party subject to recordkeeping or product transfer 
document requirements would be liable for a failure to comply with 
these requirements. Like other EPA fuels programs, the final rule 
provides that a party who causes another party to violate a prohibition 
or fail to comply with a requirement may be found liable for the 
violation.
    The Energy Act 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).\42\ Accordingly, under 
the final rule, any person who violates any prohibition or requirement 
of the RFS program may be subject to civil penalties for every day of 
each such violation and the amount of economic benefit or savings 
resulting from the violation. Under the final rule, a failure to 
acquire sufficient RINs to meet a party's renewable fuels obligation 
will constitute a separate day of violation for each day the violation 
occurred during the annual averaging period.
---------------------------------------------------------------------------

    \42\ Section 1501(b) of the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Because there are no standards under the RFS rule that may be 
measured downstream, we believe that a presumptive liability scheme, 
i.e., a scheme in which parties upstream from the facility where the 
violation is found are presumed liable for the violation, would not be 
applicable under the RFS program. As a result, the RFS rule does not 
contain such a scheme.
    The regulations prohibit any party from creating, transferring or 
using 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 RFS program goals 
are not compromised by illegal conduct in the creation and transfer of 
RINs.
    Any obligated party that reports the use of invalid RINs to meet 
its renewable fuels obligation may be liable for a regulatory violation 
for use of invalid RINs. If the obligated party fails to meet its 
renewable fuels obligation without the invalid RINs, the party may also 
be liable for not meeting its renewable fuels obligation. In addition, 
the transfer of invalid RINs is prohibited, so that any party or 
parties that transfer invalid RINs may be liable for a regulatory 
violation for transferring the invalid RINs. In a case where invalid 
RINs are transferred and used, EPA normally will hold each party that 
committed a violation responsible, including both the user and the 
transferor of the invalid RINs. For this reason, obligated parties and 
RIN brokers should use good business judgment when deciding whether to 
purchase RINs from any particular seller and should consider including 
prudent business safeguards in RIN transactions, such as requiring RIN 
sellers to sign contracts with indemnity provisions to protect the 
purchaser in the event penalties are assessed because we find the RINs 
are invalid. Similarly, parties that sell RINs should take steps to 
ensure any RINs that are sold were properly created to avoid penalties 
that result from the transfer of invalid 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. As discussed 
above, the obligated party will be liable for not meeting its renewable 
fuels obligation if the remaining number of valid RINs is insufficient 
to meet its RVO, and the obligated party may be subject to monetary 
penalties if it used invalid RINs in its compliance demonstration. In 
determining an appropriate penalty, EPA will 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. 
A penalty may include both the economic benefit of using invalid RINs 
and a gravity component.
    Although an obligated party may be liable for a violation if it 
uses invalid RINs for compliance purposes, we normally will 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 EPA is unable to

[[Page 23951]]

obtain relief from that party, attention will turn to the obligated 
party who may then be required to obtain sufficient valid RINs to 
offset the invalid RINs.
    We received several comments on the prohibition regarding use of 
invalid RINs. Some commenters believe that an obligated party that uses 
RINs which are later found to be invalid should be given an opportunity 
to ``cure'' the shortfall caused by the invalid RINs without penalty. 
As indicated above, a penalty for a good faith purchaser is not 
automatic. Where an invalid RIN was created by another party, such as 
the producer or marketer of the renewable fuel, the party responsible 
for the existence of the invalid RIN would be liable and would be 
required to purchase a RIN to make up for the invalid RIN and pay an 
appropriate penalty. If the responsible party cannot be identified or 
is out of business, or if EPA is otherwise unable to obtain relief from 
the party, then the obligated party that used the RIN would be required 
to purchase a RIN to make up for the invalid RIN. However, any penalty 
for a good faith purchaser would likely be small, particularly where 
EPA is able to obtain relief from the party that was responsible for 
the invalid RIN. Where a RIN was originally believed to be valid but is 
later found to be invalid, whether a current year RIN may be used to 
make up for the prior-year invalid RIN would be determined in the 
context of the enforcement action.
    Another commenter suggested that an obligated party should not be 
liable for a violation unless the party knowingly used the invalid RINs 
to demonstrate compliance. Where the suspect RINs are later proved to 
be valid, the party should be able to use the RINs in the subsequent 
year regardless of the year of generation or any rollover cap. For the 
reasons stated above, we believe that it is appropriate to hold an 
obligated party responsible for using invalid RINs even where the party 
in good faith believed the RINs to be valid. Normally, suspect RINs 
will be not be replaced until the RINs are proved to be invalid. In the 
unlikely circumstance that a RIN is first determined to be invalid and 
then later found to be valid, the ability to use the RIN in a 
subsequent year would be determined in the context of the enforcement 
action.
    Finally, parties that are predominately renewable fuel producers or 
importers, but which must be designated as obligated parties due to the 
production or importation of a small amount of gasoline, should not be 
able to separate RINs from all renewable fuels that they own. To 
address such circumstances, we are prohibiting obligated parties from 
separating RINs that they generate from volumes of renewable fuel in 
excess of their RVO. However, obligated parties must separate any RINs 
generated by other parties from renewable fuel if they own the 
renewable fuel.

VI. Current and Projected Renewable Fuel Production and Use

    While the definition of renewable fuel does not limit compliance 
with the standard to any one particular type of renewable fuel, ethanol 
is currently the most prevalent renewable fuel blended into gasoline 
today. Biodiesel represents another renewable fuel which, while not as 
widespread as ethanol use (in terms of volume), has been increasing in 
production capacity and use over the last several years. This section 
provides a brief overview of the ethanol and biodiesel industries today 
and how they are projected to grow into the future.

A. Overview of U.S. Ethanol Industry and Future Production/Consumption

1. Current Ethanol Production
    As of October 2006, there were 110 ethanol production facilities 
operating in the United States with a combined production capacity of 
approximately 5.2 billion gallons per year.\43\ All of the ethanol 
currently produced comes from grain or starch-based feedstocks that can 
easily be broken down into ethanol via traditional fermentation 
processes. The majority of ethanol (almost 92 percent by volume) is 
produced exclusively from corn. Another 7 percent comes from a blend of 
corn and/or similarly processed grains (milo, wheat, or barley) and 
less than 1 percent is produced from waste beverages, cheese whey, and 
sugars/starches combined. A summary of ethanol production by feedstock 
is presented in Table VI.A.1-1.
---------------------------------------------------------------------------

    \43\ The October 2006 ethanol production capacity baseline was 
generated based on the June 2006 NPRM plant list and updated on 
October 18, 2006 based on a variety of data sources including: 
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations 
(updated October 16, 2006); Ethanol Producer Magazine (EPM), plant 
list (downloaded October 18, 2006) and monthly publications (June 
2006 through October 2006); ICF International, Ethanol Industry 
Profile (September 30, 2006); BioFuels Journal, News & Information 
for the Ethanol and BioFuels Industries (breaking news posted June 
16, 2006 through October 18, 2006); and ethanol producer Web sites. 
The baseline includes small-scale ethanol production facilities as 
well as former food-grade ethanol plants that have since 
transitioned into the fuel-grade ethanol market. Where applicable, 
current ethanol plant production levels have been used to represent 
plant capacity, as nameplate capacities are often underestimated. 
This analysis does not consider ethanol plants that may be located 
in the Virgin Islands or U.S. territories.

       Table VI.A.1-1.--2006 U.S. Ethanol Production by Feedstock
------------------------------------------------------------------------
                                          Percent
       Plant feedstock         Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
Cheese Whey.................          8        0.1          2        1.8
Corn a......................      4,780       91.6         90       81.8
Corn, Barley................         40        0.8          1        0.9
Corn, Milo b................        244        4.7          8        7.3
Corn, Wheat.................         90        1.7          2        1.8
Milo, Wheat.................         40        0.8          1        0.9
Sugars, Starches............          2        0.0          1        0.9
Waste Beverages c...........         16        0.3          5        4.5
                             -------------------------------------------
    Total...................      5,218      100.0        110      100.0
------------------------------------------------------------------------
a Includes two facilities processing seed corn and another facility
  processing corn which intends to transition to corn stalks,
  switchgrass, and biomass in the future.
b Includes one facility procesisng small amounts of molasses in addition
  to corn and milo.
c Includes two facilities processing brewery waste.


[[Page 23952]]

    There are a total of 102 plants processing corn and/or other 
similarly processed grains. Of these facilities, 92 utilize dry-milling 
technologies and the remaining 10 plants rely on wet-milling processes. 
Dry mill ethanol plants grind the entire kernel and 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. In contrast to dry mill plants, wet mill facilities 
separate the kernel prior to processing and in turn produce other co-
products (usually gluten feed, gluten meal, and oil) in addition to 
DGS. Wet mill plants are generally more costly to build but are larger 
in size on average. As such, nearly 22 percent of the current overall 
ethanol production comes from the 10 previously-mentioned wet mill 
facilities.
    The remaining 8 plants which process waste beverages, cheese whey, 
or sugars/starches, operate differently than their grain-based 
counterparts. These facilities do not require milling and instead 
operate a simpler enzymatic fermentation process.
    In addition to grain and starch-to-ethanol production, another 
method exists for producing ethanol from a more diverse feedstock base. 
This process involves converting cellulosic materials such as bagasse, 
wood, straw, switchgrass, and other biomass into ethanol. Cellulose 
consists of tightly-linked polymers of starch, and production of 
ethanol from it requires additional steps to convert these polymers 
into fermentable sugars. Scientists are actively pursuing acid and 
enzyme hydrolysis as well as gasification to achieve this goal, but the 
technologies are still not fully developed for large-scale commercial 
production. As of October 2006, the only known cellulose-to-ethanol 
plant in North America was Iogen in Canada, which produces 
approximately one million gallons of ethanol per year from wood chips. 
Several companies have announced plans to build cellulose-to-ethanol 
plants in the U.S., but most are still in the research and development 
or pre-construction planning phases. The majority of the plans involve 
converting bagasse, rice hulls, wood, switchgrass, corn stalks, and 
other agricultural waste or biomass into ethanol. For a more detailed 
discussion on future cellulosic ethanol plants and production 
technologies, refer to RIA Sections 1.2.3.6 and 7.1.2, respectively.
    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 onsite or by other dedicated boilers. 
Of today's 110 ethanol production facilities, 101 burn natural gas, 7 
burn coal, 1 burns coal and biomass, and 1 burns syrup from the process 
to produce steam.\44\ Our research suggests that 11 plants currently 
utilize cogeneration or combined heat and power (CHP) technology, 
although others may exist. CHP is a mechanism for improving overall 
plant efficiency. Whether owned by the ethanol facility, their local 
utility, or a third party; CHP facilities produce their own electricity 
and use the waste heat from power production for process steam, 
reducing the energy intensity of ethanol production. A summary of the 
energy sources and CHP technology utilized by today's ethanol plants is 
found in Table VI.A.1-2.
---------------------------------------------------------------------------

    \44\ Facilities were assumed to burn natural gas if the plant 
fuel type was not mentioned or unavailable.

                         Table VI.A.1-2.--2006 U.S. Ethanol Production by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                                       Percent
                   Plant energy source                      Capacity      of     Number of   Percent   CHP tech.
                                                              MMgy     capacity    plants   of plants
----------------------------------------------------------------------------------------------------------------
Coal.....................................................      1,042       20.0          7        6.3          2
Coal, Biomass............................................         50        1.0          1        0.9          0
Natural Gas \a\..........................................      4,077       78.1        101       91.8          9
Syrup....................................................         48        0.9          1        0.9          0
                                                          ------------------------------------------------------
    Total................................................      5,218      100.0        110      100.0         11
----------------------------------------------------------------------------------------------------------------
\a\ Includes three facilities burning natural gas which intend to transition to coal or biomass in the future.

    The majority of domestic ethanol is currently produced in the 
Midwest within PADD 2--where most of the corn is grown. Of the 110 U.S. 
ethanol production facilities, 100 are located in PADD 2. As a region, 
PADD 2 accounts for 96 percent (or over five billion gallons) of the 
annual domestic ethanol production, as shown in Table VI.A.1-3.

          Table VI.A.1-3.--2006 U.S. Ethanol Production by PADD
------------------------------------------------------------------------
                                          Percent
            PADD               Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
PADD 1......................        0.4        0.0          1        0.9
PADD 2......................      5,012       96.0        100       90.9
PADD 3......................         30        0.6          1        0.9
PADD 4......................        105        2.0          4        3.6
PADD 5......................         71        1.4          4        3.6
                             -------------------------------------------
    Total...................      5,218      100.0        110      100.0
------------------------------------------------------------------------


[[Page 23953]]

    Leading the Midwest in ethanol production are Iowa, Illinois, 
Nebraska, Minnesota, and South Dakota with a combined capacity of 
nearly four billion gallons per year. Together, these five states' 70 
ethanol plants account for 76 percent of the total domestic product. 
However, although the majority of ethanol production comes from PADD 2, 
there are a growing number of plants located outside the traditional 
corn belt. In addition to the 15 states comprising PADD 2, ethanol 
plants are currently located in California, Colorado, Georgia, New 
Mexico, and Wyoming. Some of these facilities ship in feedstocks 
(namely corn) from the Midwest, others rely on locally grown/produced 
feedstocks, while others rely on a combination of both.
    The U.S. ethanol industry is currently comprised of a mixture of 
corporations and farmer-owned cooperatives (co-ops). More than half (or 
60) of today's plants are owned by corporations and, on average, these 
plants are larger in size than farmer-owned co-ops. Accordingly, 
company-owned plants account for almost 64 percent of the total U.S. 
ethanol production capacity. Further, more than 50 percent of the total 
domestic product comes from plants owned by just 6 different 
companies--Archer Daniels Midland, Broin, VeraSun, Hawkeye Renewables, 
Global/MGP Ingredients, and Aventine Renewable Energy.\45\
---------------------------------------------------------------------------

    \45\ Includes Broin's minority ownership in 18 U.S. ethanol 
plants.
---------------------------------------------------------------------------

2. Expected Growth in Ethanol Production
    Over the past 25 years, domestic fuel ethanol production has 
steadily increased due to environmental regulation, federal and state 
tax incentives, and market demand. More recently, ethanol production 
has soared due to the phase out of MTBE, an increasing number of state 
ethanol mandates, and elevated crude oil prices. As shown in Figure 
VI.A.2-1, over the past three years, domestic ethanol production has 
nearly doubled from 2.1 billion gallons in 2002 to 4.0 billion gallons 
in 2005. For 2006, the Renewable Fuels Association is anticipating 
about 4.7 billion gallons of domestic ethanol production.\46\
---------------------------------------------------------------------------

    \46\ Based on RFA comments received in response to the proposed 
rulemaking, 71 FR 55552 (September 22, 2006).
[GRAPHIC] [TIFF OMITTED] TR01MY07.047

    EPA forecasts that domestic ethanol production will continue to 
grow into the future. In addition to the past impacts of federal and 
state tax incentives, as well as the more recent impacts of state 
ethanol mandates and the removal of MTBE from all U.S. gasoline, crude 
oil prices are expected to continue to drive up demand for

[[Page 23954]]

ethanol. As a result, the nation is on track to exceed the renewable 
fuel volume requirements contained in the Act. Today's ethanol 
production capacity (5.2 billion gallons) is already exceeding the 2007 
renewable fuel requirement (4.7 billion gallons). In addition, there is 
another 3.4 billion gallons of ethanol production capacity currently 
under construction.\47\ A summary of the new construction and plant 
expansion projects currently underway (as of October 2006) is found in 
Table VI.A.2-1.
---------------------------------------------------------------------------

    \47\ Under construction plant locatons, capacities, feedstocks, 
and energy sources as well as planned/proposed plant locations and 
capacities were derived from a variety of data soruces including 
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations 
(updated October 16, 2006); Ethanol Producer Magazine (EPM), under 
construction plant list (downloaded October 18, 2006) and monthly 
publications (June 2006 through October 2006); ICF International, 
Ethanol Industry Profile (September 30, 2006); BioFuels Journal, 
News & Information for the Ethanol and BioFuels Industries (breaking 
news posted June 16, 2006 through October 18, 2006); and ethanol 
producer Web sites. This analysis does not consider ethanol plants 
under construction or planned for the Virgin Islands or U.S. 
territories.

                      Table VI.A.2-1.--Under Construction U.S. Ethanol Production Capacity
----------------------------------------------------------------------------------------------------------------
                                       Oct. 2006 baseline           Under const.           Base + under const.
               PADD               ------------------------------------------------------------------------------
                                       MMgy         Plants       MMgy a       Plants       MMgy a       Plants
----------------------------------------------------------------------------------------------------------------
PADD 1...........................           0.4            1          115            1          115            2
PADD 2...........................       5,012            100        2,764           39        7,776          139
PADD 3...........................          30              1          230            3          260            4
PADD 4...........................         105              4           50            1          155            5
PADD 5...........................          71              4          198            3          269            7
                                  ------------------------------------------------------------------------------
    Total........................       5,218            110        3,357           47        8,575         157
----------------------------------------------------------------------------------------------------------------
a Includes plant expansions.

    A select group of builders, technology providers, and construction 
contractors are completing the majority of the construction projects 
described in Table VI.A.2-1. As such, the completion dates of these 
projects are staggered over approximately 18 months, resulting in the 
gradual phase-in of ethanol production shown in Figure VI.A.2-2.\48\
---------------------------------------------------------------------------

    \48\ Construction timelines based on information obtained from 
press releases and ethanol producer Web sites.

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

[[Page 23955]]

[GRAPHIC] [TIFF OMITTED] TR01MY07.048

    As shown in Table VI.A.2-1 and Figure VI.A.2-2, once all the 
construction projects currently underway are complete (estimated by 
March 2008), the resulting U.S. ethanol production capacity would be 
about 8.6 billion gallons. Without even considering forecasted 
biodiesel production (described below in Section VI.B.1), this would be 
more than enough renewable fuel to satisfy the 2012 RFS requirements 
(7.5 billion gallons). However, ethanol production is expected to 
continue to grow. There are more and more ethanol projects being 
announced each day. These potential projects are at various stages of 
planning from conducting feasibility studies to gaining local approval 
to applying for permits to financing/fundraising to obtaining 
contractor agreements. Together these potential projects could result 
in an additional 21 billion gallons of ethanol production capacity as 
shown in Table VI.A.2-2.

                        Table VI.A.2-2.--Other Potential U.S. Ethanol Production Capacity
----------------------------------------------------------------------------------------------------------------
                                                 Base + under const.         Planned              Proposed
                     PADD                      -----------------------------------------------------------------
                                                 MMgy \a\    Plants    MMgy \a\    Plants    MMgy \a\    Plants
----------------------------------------------------------------------------------------------------------------
PADD 1........................................        115          2      548.0          8        934         21
PADD 2........................................      7,776        139      4,633         44     11,722        136
PADD 3........................................        260          4        250          4        876         14
PADD 4........................................        155          5        100          1        783         14
PADD 5........................................        269          7        232          8        775         23
                                               -----------------------------------------------------------------
        Subtotal..............................      8,575        157      5,763         65     15,090        208
                                               -----------------------------------------------------------------
        Total \b\.............................  .........  .........     14,339        222     29,428        430
----------------------------------------------------------------------------------------------------------------
\a\ Includes plant expansions.
\b\ Total including existing plus under construction plants.

    Although there is clearly a great potential for ethanol production 
growth, it is highly unlikely that all the announced projects would 
actually reach completion in a reasonable amount of time, or at all, 
considering the large number of projects moving forward. Since there is 
no precise way to know exactly which plants will come

[[Page 23956]]

to fruition in the future, we have chosen to focus our subsequent 
discussion on forecasted ethanol production on plants which are likely 
to be online by 2012.\49\ This includes existing plants as well as 
projects which are under construction (refer to Table VI.A.2-1) or in 
the final planning stages (denoted as ``planned'' in Table VI.A.2-2). 
The distinction between ``planned'' versus ``proposed'' is that as of 
October 2006 planned projects had completed permitting, fundraising/
financing, and had builders assigned with definitive construction 
timelines whereas proposed projects did not.
---------------------------------------------------------------------------

    \49\ A more detailed summary of the plants we considered is 
found in a March 5, 2007 note to the docket titled: RFS Industry 
Characterization--Ethanol Production.

       Table VI.A.2-3.--Forecasted 2012 Ethanol Production by PADD
------------------------------------------------------------------------
                                          Percent
            PADD               Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
PADD 1......................        663        4.6         10        4.5
PADD 2......................     12,409       86.5        183       82.4
PADD 3......................        510        3.6          8        3.6
PADD 4......................        255        1.8          6        2.7
PADD 5......................        501        3.5         15        6.8
                             -------------------------------------------
    Total...................     14,339      100.0        222      100.0
------------------------------------------------------------------------

    As shown above in Table VI.A.2-3, once all the under construction 
and planned projects are complete the resulting ethanol production 
capacity would be 14.3 billion gallons. The majority of which would 
still originate from PADD 2. This volume, expected to be online by 
2012, exceeds the EIA AEO 2006 demand estimate (9.6 billion gallons by 
2012, discussed more in RIA Section 2.1). The forecasted growth would 
nearly triple today's production capacity and greatly exceed the 2012 
RFS requirement (7.5 billion gallons). While our forecast represents 
ethanol production capacity (actual production could be lower), we 
believe it is still a good indicator of what domestic ethanol 
production could look like in the future. In addition, we predict that 
domestic ethanol production will continue to be supplemented by imports 
in the future. According to a current report by F.O. Licht, U.S. net 
import demand is estimated to be around 300 million gallons per year by 
2012, being supplied primarily through the Caribbean Basin Initiative 
(CBI), with some direct imports from Brazil during times of shortfall 
or high price. For more information on ethanol imports, refer to RIA 
Section 1.5.
    Of the 112 forecasted new ethanol plants (47 under construction and 
65 planned), 106 would rely on grain-based feedstocks. More 
specifically, 89 would rely exclusively on corn, 13 would process a 
blend of corn and/or similarly processed grains (milo or wheat), 3 
would process molasses, and 1 would process a combination of molasses 
and sweet sorghum (milo). Of the remaining six plants (all in the 
planned stage), four would process cellulosic biomass feedstocks and 
two would start off processing corn and later transition to cellulosic 
materials. Of the four dedicated cellulosic plants, one would process 
bagasse, one would process a combination of bagasse and wood, and two 
would process biomass. Of the two transitional corn/cellulosic plants, 
one would ultimately process a combination of bagasse, rice hulls, and 
wood and the other would ultimately process wood and other agricultural 
residues. In addition to the forecasted new plants, an existing corn 
ethanol plant plans to expand production and transition to corn stalks, 
switchgrass, and biomass in the future. A summary of the resulting 
overall feedstock usage (including current, under construction, and 
planned projects) is found in Table VI.A.2-4.

  Table VI.A.2-4.--Forecasted 2012 U.S. Ethanol Production by Feedstock
------------------------------------------------------------------------
                                          Percent
       Plant feedstock         Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
Bagasse.....................          7        0.1          1        0.5
Bagasse, Wood...............          2        0.0          1        0.5
Bagasse, Wood, Rice Hulls           108        0.8          1        0.5
 \a\........................
Biomass.....................         55        0.4          2        0.9
Cheese Whey.................          8        0.1          2        0.9
Corn \b\....................     12,495       87.1        178       80.2
Corn, Barley................         40        0.3          1        0.5
Corn, Milo \c\..............      1,132        7.9         20        9.0
Corn, Wheat.................        235        1.6          3        1.4
Corn Stalks, Switchgrass,            40        0.3          1        0.5
 Biomass \a\................
Milo, Wheat.................         40        0.3          1        0.5
Molasses \d\................         52        0.4          4        1.8
Sugars, Starches............          2        0.0          1        0.5
Waste Beverages \e\.........         16        0.1          5        2.3
Wood Agricultural Residues          108        0.8          1        0.5
 \a\........................
                             -------------------------------------------
    Total...................     14,339      100.0        222      100.0
------------------------------------------------------------------------
\a\ Facilities plan to start off processing corn.

[[Page 23957]]


\b\ Includes two facilities processing seed corn.
\c\ Includes one facility processing small amounts of molasses in
  addition to corn and milo.
\d\ Includes one facility planning to process sweet sorghum (milo) in
  addition to molasses.
\e\ Includes two facilities processing brewery waste.

    Of the 112 forecasted new plants, 100 would burn some amount of 
natural gas--at least initially. More specifically, 91 plants would 
rely exclusively on natural gas; 2 would rely on a combination of 
natural gas, bran and biomass; 1 would burn a combination of natural 
gas, distillers' grains and syrup; and 6 would start off burning 
natural gas and later transition to coal. As for the remaining 12 
plants, 3 would burn manure-derived methane (biogas); 7 would rely 
exclusively on coal; 1 would burn a combination of coal and biomass; 
and 1 would burn a combination of coal, tires and biomass. In addition 
to the new ethanol plants, three existing plants currently burning 
natural gas are predicted to transition to alternate boiler fuels in 
the future. More specifically, two plants plan to transition to biomass 
and one plans to start burning coal. Our research suggests that 7 of 
the new plants would utilize combined heat and power (CHP) technology, 
although others may exist. Three of the new CHP plants would burn 
natural gas, three would burn coal, and one would burn a combination of 
coal, tires, and biomass. Among the existing CHP plants, two are 
predicted to transition from natural gas to coal or biomass at this 
time. Overall, the net number of CHP ethanol plants would increase from 
11 to 18. A summary of the resulting overall plant energy source 
utilization is found below in Table VI.A.2-5.

                    Table VI.A.2-5.--Forecasted 2012 U.S. Ethanol Production by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                                       Percent
                   Plant energy source                      Capacity      of     Number of   Percent   CHP tech.
                                                              MMgy     capacity    plants   of plants
----------------------------------------------------------------------------------------------------------------
Biomass \a\..............................................        112        0.8          2        0.9          1
Coal \b\.................................................      2,095       14.6         21        9.5          6
Coal, Biomass............................................         75        0.5          2        0.9          0
Coal, Biomass, Tires.....................................        275        1.9          1        0.5          1
Manure Biogas \c\........................................        144        1.0          3        1.4          0
Natural Gas..............................................     11,275       78.6        189       85.1         10
Natural Gas, Bran, Biomass...............................        264        1.8          2        0.9          0
Natural Gas, Distiller's Grain, Syrup....................         50        0.3          1        0.5          0
Syrup....................................................         49        0.3          1        0.5          0
                                                          ------------------------------------------------------
    Total................................................     14,339      100.0        222      100.0         18
----------------------------------------------------------------------------------------------------------------
\a\ Represents two existing natural gas-fired plants that plan to transition to biomass.
\b\ Includes two plants planning on burning lignite coal or coal lines. Includes one existing plant currently
  burning natural gas that plans to transition to coal. Includes six new plants that will start off burning
  natural gas and later transition to coal.
\c\ Includes one facility planning on burning cotton gin in addition to manure biogas.

    The Energy Policy Act of 2005 requires that 250 million gallons of 
the renewable fuel consumed in 2013 and beyond meet the definition of 
cellulosic biomass ethanol. The Act defines cellulosic biomass ethanol 
as ethanol derived from any lignocellulosic or hemicellulosic matter 
that is available on a renewable or recurring basis including dedicated 
energy crops and trees, wood and wood residues, plants, grasses, 
agricultural residues, fibers, animal wastes and other waste materials, 
and municipal solid waste. The term also includes any ethanol produced 
in facilities where animal or other waste materials are digested or 
otherwise used to displace 90 percent of more of the fossil fuel 
normally used in the production of ethanol.
    As shown in Table VI.A.2-4, there are seven ethanol plants planning 
to utilize cellulosic feedstocks in the future. These facilities have a 
combined ethanol production capacity of 320 million gallons per year. 
It is unclear whether these plants would be online and capable of 
producing 250 million gallons of ethanol by 2013 to meet the Act's 
cellulosic biomass ethanol requirement. However, as shown in Table 
VI.A.2-5, there are 12 facilities that burn or plan to burn waste 
materials to power their ethanol plants. Depending on how much fossil 
fuel is displaced, these facilities (with a combined ethanol production 
capacity of 969 million gallons per year) could also meet the 
definition of cellulosic biomass ethanol under the Act. Considering 
both feedstock and waste energy plants, the total cellulosic ethanol 
potential could be as high as 1.3 billion gallons. Even if only one 
fifth of this ethanol were to end up qualifying as cellulosic biomass 
ethanol or come to fruition by 2013, it would be more than enough to 
satisfy the 250 million gallon requirement specified in the Act.\50\
---------------------------------------------------------------------------

    \50\ We anticipate a ramp-up in cellulosic ethanol production in 
the years to come so that capacity exists to satisfy the Act's 2013 
requirement (250 million gallons of cellulosic biomass ethanol). 
Therefore, for subsequent analysis purposes, we have assumed that 
250 million gallons of ethanol would come from cellulosic biomass 
sources by 2012.
---------------------------------------------------------------------------

3. Current Ethanol and MTBE Consumption
    To understand the impact of the increased ethanol production/use on 
gasoline properties and in turn overall air quality, we first need to 
gain a better understanding of where ethanol is used today and how the 
picture is going to change in the future. As such, in addition to the 
production analysis presented above, we have completed a parallel 
consumption analysis comparing current ethanol consumption to future 
predictions.
    In the 2004 base case, 3.5 billion gallons of ethanol \51\ and 1.9 
billion gallons of MTBE \52\ were blended into gasoline to supply the 
transportation sector with a total of 136 billion gallons of 
gasoline.\53\ A breakdown of the 2004

[[Page 23958]]

gasoline and oxygenate consumption by PADD is found below in Table VI-
A.3-1.
---------------------------------------------------------------------------

    \51\ EIA Monthly Energy Review, June 2006 (Table 10.1: Renewable 
Energy Consumption by Source, Appendix A: Thermal Conversion 
Factors).
    \52\ File containing historical RFG MTBE usage obtained from EIA 
representative on March 9, 2006.
    \53\ EIA 2004 Petroleum Marketing Annually (Table 48: Prime 
Supplier Sales Volumes of Motor Gasoline by Grade, Formulation, PAD 
District, and State).

                       Table VI.A.3-1.--2004 U.S. Gasoline & Oxygenate Consumption by PADD
----------------------------------------------------------------------------------------------------------------
                                                                       Ethanol                  MTBE \a\
                                                   Gasoline  ---------------------------------------------------
                      PADD                          MMgal                   Percent of                Percent of
                                                                 MMgal       gasoline      MMgal       gasoline
----------------------------------------------------------------------------------------------------------------
PADD 1.........................................       49,193          660          1.3        1,360          2.8
PADD 2.........................................       38,789        1,616          4.2            1          0.0
PADD 3.........................................       20,615           79          0.4          498          2.4
PADD 4.........................................        4,542           83          1.8            0          0.0
PADD 5 \b\.....................................        7,918          209          2.6           19          0.2
California.....................................       14,836          853          5.8            0          0.0
                                                ----------------------------------------------------------------
    Total......................................      135,893        3,500          2.6        1,878         1.4
----------------------------------------------------------------------------------------------------------------
\a\ MTBE blended into RFG.
\b\ PADD 5 excluding California.

    As shown above, nearly half (or about 45 percent) of the ethanol 
was consumed in PADD 2 gasoline, where the majority of ethanol was 
produced. The next highest region of use was the State of California 
which accounted for about 25 percent of domestic ethanol consumption. 
This is reasonable because California alone accounts for over 10 
percent of the nation's total gasoline consumption and all the fuel 
(both Federal RFG and California Phase 3 RFG) has been assumed to 
contain ethanol (following their recent MTBE ban) at 5.7 volume 
percent.\54\ The bulk of the remaining ethanol was used in reformulated 
gasoline (RFG) and winter oxy-fuel areas requiring oxygenated gasoline. 
Overall, 62 percent of ethanol was used in RFG, 33 percent was used in 
CG, and 5 percent was used in winter oxy-fuel.\55\
---------------------------------------------------------------------------

    \54\ Current California gasoline regualtions make it very 
difficult to meet the NOX emissions performance standard 
with ethanol content higher than about 6 vol%. For our analysis, all 
California RFG was assumed to contain 5.7 volume percent ethanol 
based on a conversation with Dean Simeroth at California Air 
Resources Board (CARB).
    \55\ For the purpose of this analysis, except where noted, the 
term ``RFG'' pertains to Federal RFG plus California Phase 3 RFG 
(CaRFG3) and Arizona Clean Burning Gasoline (CBG).
---------------------------------------------------------------------------

    As shown above in Table VI.A.3-1, 99 percent of MTBE use occurred 
in PADDs 1 and 3. This reflects the high concentration of RFG areas in 
the northeast (PADD 1) and the local production of MTBE in the gulf 
coast (PADD 3). PADD 1 receives a large portion of its gasoline from 
PADD 3 refineries who either produce the fossil-fuel based oxygenate or 
are closely affiliated with MTBE-producing petrochemical facilities in 
the area. Overall, 100 percent of MTBE in 2004 was assumed to be used 
in reformulated gasoline.\56\
---------------------------------------------------------------------------

    \56\ 2004 MTBE consumption was obtained from EIA. The data 
received was limited to states with RFG programs, thus MTBE use was 
assumed to be limited to RFG areas for the purpose of this analysis.
---------------------------------------------------------------------------

    In 2004, total ethanol use exceeded MTBE use. Ethanol's lead 
oxygenate role is relatively new, however the trend has been a 
progression over the past few years. From 2001 to 2004, ethanol 
consumption more than doubled (from 1.7 to 3.5 billion gallons), while 
MTBE use (in RFG) was virtually cut in half (from 3.7 to 1.9 billion 
gallons). A plot of oxygenate use over the past decade is provided 
below in Figure VI.A.3-1.
    The nation's transition to ethanol is linked to states' responses 
to recent environmental concerns surrounding MTBE groundwater 
contamination. Resulting concerns over drinking water quality have 
prompted several states to significantly restrict or completely ban 
MTBE use in gasoline. At the time of this analysis, 19 states had 
adopted MTBE bans. A list of the states with MTBE bans is provided in 
RIA Table 2.1-4.

[[Page 23959]]

[GRAPHIC] [TIFF OMITTED] TR01MY07.049

4. Expected Growth in Ethanol Consumption
    As mentioned above, ethanol demand is expected to increase well 
beyond the levels contained in the renewable fuels standard (RFS) under 
the Act. With the removal of the RFG oxygenate mandate,\57\ all U.S. 
refiners are taking steps to eliminate the use of MTBE as quickly as 
possible. In order to complete this transition quickly (by 2007 at the 
latest) while maintaining gasoline volume, octane, and mobile source 
air toxics emission performance standards, refiners have elected to 
blend ethanol into virtually all of their RFG.\58\ This has caused a 
dramatic increase in demand for ethanol which, in 2006, was met by 
temporarily shifting large volumes of ethanol out of conventional 
gasoline and into RFG areas. By 2012, however, ethanol production will 
have grown to accommodate the removal of MTBE without the need for such 
a shift from conventional gasoline. More important than the removal of 
MTBE over the long term, however, is the impact that the rise in crude 
oil price is having on demand for renewable fuels, both ethanol and 
biodiesel. This has dramatically improved the economics for renewable 
fuel use, leading to a surge in demand that is expected to continue. In 
the Annual Energy Outlook (AEO) 2006, EIA forecasted that by 2012, 
total ethanol use (corn, cellulosic, and imports) would be about 9.6 
billion gallons and biodiesel use would be about 0.3 billion gallons at 
a crude oil price forecast of $48 per barrel.\59\ This ethanol 
projection was not based on what amount the market would demand (which 
could be higher), but rather on the amount that could be produced by 
2012. Others are making similar predictions, and as discussed above in 
VI.A.2, production capacity would be sufficient.
---------------------------------------------------------------------------

    \57\ Energy Act Section 1504, promulgated on May 8, 2006 at 71 
FR 26691.
    \58\ Based on discussions with the refining industry.
    \59\ In AEO 2007, EIA is forecasted an even higher ethanol 
consumption of 11.2 billion gallons by 2012. The draft report was 
issued on December 5, 2006 and we could not incorporate it into the 
refinery modeling used to conduct our analyses.
---------------------------------------------------------------------------

    In assessing the impacts of expanded renewable fuel use, we have 
chosen to evaluate two different future ethanol consumption levels, one 
reflecting the statutory required minimum, and one reflecting the 
higher levels projected by EIA. For the statutory consumption scenario 
we assumed 6.7 billion gallons of ethanol use (0.25 billion gallons of 
which was assumed to be cellulosic) and 0.3 billion gallons of 
biodiesel. This figure is lower than the 7.2 billion gallons of ethanol 
we modeled in the proposal because it considers the renewable fuel 
equivalence values we are finalizing for corn ethanol (1), biodiesel 
(1.5) and cellulosic ethanol (2.5). For the higher projected renewable 
fuel consumption scenario, we assumed 9.6 billion gallons of ethanol 
(0.25 billion gallons of which was assumed to be cellulosic) and 0.3 
billion gallons of biodiesel. Although the actual renewable fuel 
volumes consumed in 2012 may differ from both the required and 
projected volumes, we believe that

[[Page 23960]]

these two scenarios provide a reasonable range for analysis purposes. 
For more information on how the renewable fuel usage scenarios we 
considered, refer to RIA Section 2.1.
    To estimate where ethanol would be consumed in 2012, we used a 
linear programming (LP) refinery cost model (discussed in more detail 
in Section VII). For both future ethanol consumption scenarios 
discussed above, the modeling provided us with a summary of ethanol 
usage by PADD, fuel type, and season. There was some post-processing 
involved to ensure that all state ethanol mandates and winter oxy-fuel 
requirements were satisfied. The adjusted results for the 6.7 Bgal RFS 
case and the 9.6 Bgal EIA case are presented below in Tables VI.A.4-1 
and VI.A.4-2, respectively.

               Table VI.A.4-1.--Forecasted 2012 U.S. Ethanol Consumption (MMgal) 6.7 Bgal RFS Case
----------------------------------------------------------------------------------------------------------------
                                            Summer ethanol use               Winter ethanol use
                PADD                ------------------------------------------------------------------   Total
                                       CG \a\    RFG \b\     Total      CG \a\    RFG \b\     Total     ethanol
----------------------------------------------------------------------------------------------------------------
PADD 1.............................        399        679      1,078        350        706      1,057      2,134
PADD 2.............................      1,667         59      1,726      1,082        288      1,370      3,096
PADD 3.............................        161         47        208        146          0        146        354
PADDs 4/5 c........................        135          0        135        138          0        138        274
California.........................          0        414        414          0        398        398        813
                                    ----------------------------------------------------------------------------
    Total..........................      2,362      1,200      3,562      1,717      1,392      3,109      6,671
----------------------------------------------------------------------------------------------------------------
\a\ Includes Arizona CBG and winter oxy-fuel.
\b\ Federal RFG and California Phase 3 RFG.
\c\ PADDS 4 and 5 excluding California.


          Table VI.A.4-1.--Forecasted 2012 U.S. Ethanol Consumption by Season (MMgal) 9.6 Bgal EIA Case
----------------------------------------------------------------------------------------------------------------
                                            Summer ethanol use               Winter ethanol use
                PADD                ------------------------------------------------------------------   Total
                                       CG \a\    RFG \b\     Total      CG \a\    RFG \b\     Total     ethanol
----------------------------------------------------------------------------------------------------------------
PADD1..............................        610        630      1,240        267        973      1,240      2,481
PADD2..............................      1,735        185      1,919      1,631        366      1,998      3,917
PADD3..............................        901         47        949        856          0        856      1,805
PADD 4/5 \c\.......................        339          0        339        154          0        154        492
California.........................          0        435        435          0        470        470        905
                                    ----------------------------------------------------------------------------
    Total..........................      3,584      1,298      4,882      2,908      1,809      4,718      9,600
----------------------------------------------------------------------------------------------------------------
\a\ Includes Arizona CBG and winter oxy-fuel.
\b\ Federal RFG and California Phase 3 RFG.
\c\ PADDs 4 and 5 excluding California.

    As shown above, the LP modeling predicts that the majority of 
ethanol will be consumed in PADD 2, where most of the ethanol is 
produced. The results show varying levels of ethanol usage in RFG in 
response to the removal of the oxygenate requirement. For the higher 
ethanol consumption scenario, the modeling suggests that the majority 
of additional ethanol would be absorbed in PADD 3 conventional 
gasoline. With respect to seasonality, in both cases, the modeling 
predicts that a greater fraction of ethanol use would occur in the 
summertime due to the 1psi RVP waiver. For a more detailed discussion 
on future ethanol consumption, refer to Chapter 2 of the RIA.

B. Overview of Biodiesel Industry and Future Production/Consumption

1. Characterization of U.S. Biodiesel Production/Consumption
    Historically, the cost to make biodiesel was an inhibiting factor 
to production in the U.S. The cost to produce biodiesel was high 
compared to the price of petroleum derived diesel fuel, even with the 
subsidies and credits provided by federal and state programs. Much of 
the demand occurred as a result of mandates from states and local 
municipalities, that required the use of biodiesel. However, over the 
past couple of years biodiesel production has been increasing rapidly. 
The combination of higher crude oil prices and greater federal tax 
subsidies has created a favorable economic situation. The Biodiesel 
Blenders Tax Credit programs and the Commodity Credit Commission Bio-
energy Program, both subsidize producers and offset production costs. 
The Energy Policy Act extended the Biodiesel Blenders Tax Credit 
program to 2008. This credit provides about one dollar per gallon in 
the form of a federal excise tax credit to biodiesel blenders from 
virgin vegetable oil feedstocks and 50 cents per gallon to biodiesel 
produced from recycled grease and animal fats. The program was started 
in 2004 under the American Jobs Act, spurring the expansion of 
biodiesel production and demand. Historical estimates and future 
forecasts of biodiesel production in the U.S. are presented in Table 
VI.B.1-1 below.

             Table VI.B.1-1.--Estimated Biodiesel Production
------------------------------------------------------------------------
                                                                Million
                             Year                               gallons
                                                                per year
------------------------------------------------------------------------
2001.........................................................          5
2002.........................................................         15
2003.........................................................         20
2004.........................................................         25
2005.........................................................         91
2006.........................................................        150
2007.........................................................        414
2012.........................................................       303
------------------------------------------------------------------------
Source: Historical data from 2001-2004 obtained from estimates from John
  Baize `` The Outlook and Impact of Biodiesel on the Oilseeds Sector''
  USDA Outlook Conference 06. Year 2005 data from USDA Bioenergy Program
  http://www.fsa.usda.gov/daco/bioenergy/2005/FY2005ProductPayments,

  Year 2006 data from verbal quote based on projection by NBB in June of
  2006. Production data for years 2007 and higher are from EIA's AEO
  2006.

    With the increase in biodiesel production, there has also been a

[[Page 23961]]

corresponding rapid expansion in biodiesel production capacity. 
Presently, there are 85 biodiesel plants in operation with an annual 
production capacity of 580 million gallons per year.\60\ The majority 
of the current production capacity was built in 2005 and 2006, and was 
first available to produce fuel in the later part of 2005 and in 2006. 
Though the capacity has grown, historically the biodiesel production 
capacity has far exceeded actual production with only 10-30 percent of 
this being utilized to make biodiesel. The excess capacity, though, may 
be from biodiesel plants that do not operate full time and from 
production capacity that is primarily devoted to making esters for the 
ole-chemical markets, see Table VI.B.1-2.
---------------------------------------------------------------------------

    \60\ NBB Survey September 13, 2006 ``U.S. Biodiesel Production 
Capacity''.
    \61\ From Presentation ``Biodiesel Production Capacity,'' by 
Leland Tong, National Biodiesel Conference and Expo, February 7, 
2006.

           Table VI.B.1-2.--U.S. Production Capacity History a
------------------------------------------------------------------------
                                 2001   2002   2003   2004   2005   2006
------------------------------------------------------------------------
Plants........................      9     11     16     22     45     85
Capacity (million gal/yr).....     50     54     85    157    290   580
------------------------------------------------------------------------
\a\ Capacity Data based on surveys conducted around the month of
  September for most years, though the 2006 information is based on a
  survey conducted in January 2006.\61\

2. Expected Growth in U.S. Biodiesel Production/Consumption
    In addition to the 85 biodiesel plants already in production, as of 
early 2006, there were 65 plants in the construction phase and 13 
existing plants that are expanding their capacity, which when completed 
would increase total biodiesel production capacity to over one billion 
gallons per year. Most of these plants should be completed by late 
2007. As shown in Table VI.B.2-1 if all of this capacity came to 
fruition, U.S. biodiesel capacity would exceed 1.4 billion gallons.

        Table VI.B.2-1.--Projected Biodiesel Production Capacity
------------------------------------------------------------------------
                                             Existing      Construction
                                              plants           phase
------------------------------------------------------------------------
Number of plants........................              85              78
Total Plant Capacity, (MM Gallon/year)..             580           1,400
------------------------------------------------------------------------

    For cost and emission analysis purposes, three biodiesel usage 
cases were considered: A 2004 base case, a 2012 reference case, and a 
2012 control case. The 2004 base case was formed based on historical 
biodiesel usage (25 million gallons as summarized in Table VI.B.1.1). 
The reference case was computed by taking the 2004 base case and 
growing it out to 2012 by applying the 2004-2012 EIA diesel fuel growth 
rate.\62\ The resulting 2012 reference case consisted of 30 million 
gallons of biodiesel. Finally, for the 2012 control case, forecasted 
biodiesel use was assumed to be 300 million gallons based on EIA's AEO 
2006 report (rounded value from Table VI.B.1.1). Unlike forecasted 
ethanol use, biodiesel use was assumed to be constant at 300 million 
gallons under both the statutory and higher projected renewable fuel 
consumption scenarios described in VI.A.4. EIA's projection is based on 
the assumption that the blender's tax credit is not renewed beyond 
2008. If the tax credit is renewed, the projection for biodiesel demand 
would increase.
---------------------------------------------------------------------------

    \62\ EIA Annual Energy Outlook 2006, Table 1.
---------------------------------------------------------------------------

C. Feasibility of the RFS Program Volume Obligations

    This section examines whether there are any feasibility issues 
associated with the meeting the minimum renewable fuel requirements of 
the Energy Act. Issues are examined with respect to renewable 
production capacity, cellulosic ethanol production capacity, and 
distribution system capability. Land resource requirements are 
discussed in Chapter 7 of the RIA.
1. Production Capacity of Ethanol and Biodiesel
    As shown in Sections VI.A. and VI.B., increases in renewable fuel 
production capacity are already proceeding at a pace significantly 
faster than required to meet the 2012 mandate in the Act of 7.5 billion 
gallons as well as the mandate (starting in 2013) of a minimum of 250 
million gallons of cellulosic ethanol. The combination of ethanol and 
biodiesel plants in existence and planned or under construction is 
expected to provide a total renewable fuel production capacity of over 
9.6 billion gallons by the end of 2012. Production capacity is expected 
to continue to increase in response to strong demand. We estimate that 
this will require a maximum of 2,100 construction workers and 90 
engineers on a monthly basis through 2012.
2. Technology Available To Produce Cellulosic Ethanol
    There are a wide variety of government and renewable fuels industry 
research and development programs dedicated to improving our ability to 
produce renewable fuels from cellulosic feedstocks. In this discussion, 
we deal with at least three completely different approaches to 
producing ethanol from cellulosic biomass. The first is based on what 
NREL refers to as the ``sugar platform,'' \63\ which refers to 
pretreating the biomass, then hydrolyzing the cellulosic and 
hemicellulosic components into sugars, and then fermenting the sugars 
into ethanol.
---------------------------------------------------------------------------

    \63\ Enzyme Sugar Platform (ESP), Project Next Steps National 
Renewable Energy, Dan Schell, FY03 Review Meeting; Laboratory 
Operated for the U.S. Department of Energy by Midwest Research 
Institute  B NREL, Golden, Colorado, May 1-2, 2003; U.S. 
Department of Energy by Midwest Research Institute  Battelle 
 Bechtel.
---------------------------------------------------------------------------

    Corn grain is a nearly ideal feedstock for producing ethanol by 
fermentation, especially when compared with cellulosic biomass 
feedstocks. Corn grain is easily ground into small particles, following 
which the exposed starch which has [alpha]-linked saccharide polymers 
is easily hydrolyzed into

[[Page 23962]]

simple, single component sugar which can then be easily fermented into 
ethanol. By comparison, the biomass lignin structure must be either 
mechanically or chemically broken down to permit hydrolyzing chemicals 
and enzymes access to the saccharide polymers. The central problem is 
that the cellulose/hemicellulose saccharide polymers are [beta]-linked 
which makes hydrolysis much more difficult. Simple microbial 
fermentation used in corn sugar fermentation is also not possible, 
since the cellulose and hemicellulose (6 & 5 carbon molecules, 
respectively) have not been able to be fermented by the same microbe. 
We discuss various pretreatment, hydrolysis and fermentation 
technologies, below. The second and third approaches have nothing to do 
with pretreatment, acids, enzymes, or fermentation. The second is 
sometimes referred to as the ``syngas'' or ``gas-to-liquid'' approach; 
we will call it the ``Syngas Platform.'' Briefly, the cellulosic 
biomass feedstock is steam-reformed to produce syngas which is then 
converted to ethanol over a Fischer-Tropsch catalyst. The third 
approach uses plasma technology.
a. Sugar Platform
    Plant cell walls are made up of cellulose and hemicellulose 
polymers embedded in a lignin matrix. This complex structure prevents 
both the first step, hydrolyzation of the cellulose and hemicellulose 
polymers, and the second step, fermentation of the hydrolyzed sugars 
into ethanol.
i. Pretreatment
    Those who wish to use cellulosic biomass feedstocks to produce 
ethanol face several, difficult problems. The lignin sheath, present in 
all cellulosic materials, prevents, or at the very least, severely 
restricts hydrolysis. To produce ethanol from cellulosic biomass 
feedstocks by fermentation, some type of thermo-mechanical, mechanical, 
chemical or a combination of these pretreatments is always necessary 
before the cellulosic and hemicellulosic polymers can be hydrolyzed. In 
effect, the lignin structure must be ``opened'' to allow efficient and 
effective strong acid hydrolysis, weak acid hydrolysis, or weak acid 
enzymatic hydrolysis of the cellulose/hemicellulose to their glucose 
and xylose sugar components. Over time, many pretreatment methods or 
combinations of methods have been tried, some with more success than 
others. Usually, intense physical pretreatments such as steam explosion 
are required; grasses and forest thinnings usually need to be chipped, 
prior to chemical or enzymatic hydrolysis. The most common chemical 
pretreatments for cellulosic feedstocks are strong acid, dilute acid, 
caustic, organic solvents, ammonia, sulfur dioxide, carbon dioxide or 
other chemicals which make the biomass more accessible to the enzymes. 
Following pretreatment, acidic (dilute and concentrated) and enzymatic 
hydrolysis are the two process types commonly used to hydrolyze 
cellulosic feedstocks before fermentation into ethanol.\64\
---------------------------------------------------------------------------

    \64\ Appendix B, Overview of Cellulose-Ethanol Production 
Technology; OREGON CELLULOSE-ETHANOL STUDY, An evaluation of the 
potential for ethanol production in Oregon using cellulose-based 
feedstocks; Prepared by: Angela Graf, Bryan & Bryan Inc., 5015 Red 
Gulch, Cotopaxi, Colorado 81223; Tom Koehler, Celilo Group, 2208 
S.W. First Ave, 320, Portland, Oregon 97204; For submission 
to: The Oregon Office of Energy.
---------------------------------------------------------------------------

ii. Dilute Acid Hydrolysis
    Dilute acid hydrolysis is the oldest technology for converting 
cellulose biomass to ethanol. The dilute acid process uses a 1-percent 
sulfuric acid in a continuous flow reactor at about 420 [deg]F; 
reaction times are measured in seconds and minutes, which facilitates 
continuous processing. The process involves two reactions with a sugar 
conversion efficiency of about 50 percent. The process conditions at 
which the cellulosic molecules are converted into sugar are also those 
at which the sugar is almost immediately converted into other 
chemicals, principally furfural. The rapid conversion to furfural 
reduces the sugar yield, which along with other by-products inhibits 
the fermentation process. One way to decrease sugar degradation is to 
use a two-stage process which takes advantage of the fact that 
hemicellulose (5-carbon) sugars degrade more rapidly than cellulose (6-
carbon) sugars. The first stage is conducted under mild process 
conditions to recover the 5-carbon sugars, while the second stage is 
conducted under harsher conditions to recover the 6-carbon sugars. Both 
hydrolyzed solutions are then fermented to ethanol. Lime is used to 
neutralize the residual acid before the fermentation stage. Regardless, 
some sugar degrades to furfural, which naturally limits the net yield 
of ethanol. The residual cellulose and lignin are used as boiler fuel 
for electricity or steam production.\65\
---------------------------------------------------------------------------

    \65\ Ibid.
---------------------------------------------------------------------------

iii. Concentrated acid hydrolysis
    Concentrated acid hydrolysis uses a 70-percent sulfuric acid 
solution, followed by water hydrolysis to convert the cellulose into 
sugar. The process rapidly, and nearly completely, converts cellulose 
to glucose (6-carbon) and hemicellulose to xylose (5-carbon) sugar, 
with little degradation to furfural; the reaction times are typically 
slower than those of the dilute acid process. The critical factors 
needed to make this process economically viable are to optimize sugar 
recovery and cost effectively recover the acid for recycling. The 
concentrated acid process is somewhat more complicated and requires 
more time, but it has the primary advantage of yielding up to about 90% 
of both hemicellulosic and cellulosic sugars.\66\ In addition, a 
significant advantage of the concentrated acid process is that it is 
carried out at relatively low temperatures, about 212 [deg]F, and low 
pressure, such that fiberglass reactors and piping can be used.
---------------------------------------------------------------------------

    \66\ Ibid.
---------------------------------------------------------------------------

iv. Enzymatic hydrolysis
    Enzymatic hydrolysis is not necessarily a recent discovery. We 
found reports of research conducted by a variety of companies and 
government agencies going back to at least 1991. 67 68 69 
The enzymatic hydrolysis of cellulose was reportedly discovered when a 
fungus, trichoderma reesei, was identified which produced cellulase 
enzymes that broke down cotton clothing and tents in the South Pacific 
during World War II. Since then, generations of cellulases have been 
developed through genetic modifications of the fungus strain. As in 
acid hydrolysis, the hydrolyzing enzymes must have access to the 
cellulose and hemicellulose in order to work efficiently. Although 
enzymatic hydrolysis requires some kind of pretreatment, purely 
physical pretreatments are typically not adequate. Furthermore, the 
chemical method uses dilute sulfuric acid, which is poisonous to the 
fermentation

[[Page 23963]]

microorganisms and must be detoxified. While original enzymatic 
hydrolysis processes used separate hydrolysis and fermentation steps, 
recent process improvements integrate saccharification and fermentation 
by combining the cellulase enzymes and fermenting microbes in one 
vessel. This results in a one-step process of sugar production and 
fermentation, referred to as the simultaneous saccharification and 
fermentation (SSF) process. One disadvantage is that the cellulase 
enzyme and fermentation organism must operate under the same process 
conditions, which could decrease the sugar and, ultimately, the ethanol 
yields. An alternative to the SSF technology is the sequential 
hydrolysis and fermentation (SHF) process. The separation of hydrolysis 
and fermentation enables enzymes to operate at higher temperatures in 
the hydrolysis step to increase sugar production and more moderate 
temperatures in the fermentation step to optimize the conversion of 
sugar into ethanol.
---------------------------------------------------------------------------

    \67\ Technical and Economic Analysis Of An Enzymatic Hydrolysis 
Based Ethanol Plant, Fuels and Chemicals Research and Engineering 
Division, Solar Energy Research Institute, Golden CO, 80401, June 
1991  DRAFT  SERI Protected Proprietary Information 
 Do Not Copy.
    \68\ Biomass to Ethanol Process Evaluation, A report prepared 
for National Renewable Energy Laboratory, December 1994; Chem 
Systems Inc. 303 South Broadway, Tarrytown, New York, 10591.
    \69\ Lignocellulosic Biomass to Ethanol Process Design and 
Economics Utilizing Co-Current Dilute Acid Prehydrolysis and 
Enzymatic Hydrolysis Current and Futuristic Scenarios, July 1999 
 NREL/TP-580-26157; Robert Wooley, Mark Ruth, John Sheehan, 
and Kelly Ibsen, Biotechnology Center for Fuels and Chemicals; Henry 
Majdeski and Adrian Galvez, Delta-T Corporation; National Renewable 
Energy Laboratory, 1617 Cole Boulevard, Golden, Colorado 80401-3393; 
NREL is a U.S. Department of Energy Laboratory Operated by Midwest 
Research Institute  Battelle  Bechtel; Contract No. 
DE-AC36-98-GO10337.
---------------------------------------------------------------------------

    Cost-effective cellulase enzymes must also be developed for this 
technology to be completely successful.\70\ Several companies are using 
variations of these technologies to develop processes for converting 
cellulosic biomass into ethanol by way of fermentation. A few groups, 
using recently developed genome modifying technology, have been able to 
produce a variety of new or modified enzymes and microbes that show 
promise for use in weak- or dilute-acid enzymatic-prehydrolysis. 
Another problem with cellulosic feedstocks is, as previously described, 
that the hydrolysis reactions produce both glucose, the six-carbon 
sugar, and xylose, the five-carbon sugar (pentose sugar, 
C5H10O5; sometimes called ``wood 
sugar''). Early conversion technology required different microbes to 
ferment each sugar. Recent research has developed better fermenting 
organisms. Now, glucose and xylose can be co-fermented--hence, the 
present-day terminology: Weak-acid enzymatic hydrolysis and co-
fermentation.
---------------------------------------------------------------------------

    \70\ Ibid.
---------------------------------------------------------------------------

b. Syngas Platform
    The second platform for producing cellulosic ethanol is to convert 
the biomass into a syngas which is then converted into ethanol. A 
``generic'' syngas process is essentially a ``steam reformer,'' which 
``gasifies'' biomass and other carbon based substances including 
wastes, in a reduced-oxygen environment and reacts them with steam to 
produce a synthesis gas or ``syngas'' consisting primarily of carbon 
monoxide and hydrogen. The syngas is then passed over in a Fischer-
Tropsch catalyst to produce ethanol.
    The biomass feedstock is dried to about 15% moisture content and 
ground small enough to be efficiently burned and reacted in the 
reformer. The reformer, an important upstream element of the process, 
is essentially a common solid-fuel gasifier, which with some 
modification and steam injection becomes what is sometimes referred to 
as the ``primary reformer.''
    When any fuel is completely burned, all of its potential energy is 
released as heat which can be recovered for immediate use. In a common 
gasification process, the partially burned fuel (wood or coal) releases 
a small amount of heat, but leaves some uncombusted, gaseous products. 
Ordinarily, the hot product gases are fed directly to a nearby boiler 
or gas turbine, to do work; it has been reported that for a well-
designed system, the overall efficiency may approach that of a solid 
fuel boiler. However, when steam is injected into the gasifier, it 
reacts with the burning solid fuel to produce more gaseous product. The 
primary reaction is between carbon and water which produces hydrogen 
and carbon monoxide and an inorganic ash. The ash and heavy 
hydrocarbon-tars are removed from the raw syngas before it is 
compressed and passed over Fisher-Tropsch catalyst to produce ethanol. 
Fisher-Tropsch technology has been used for many years in the chemical 
and refining industries, most notably to produce gasoline and diesel 
fuel from syngas produced by coal gasification. Whether the Fischer-
Tropsch reaction produces diesel or ethanol is primarily the result of 
changes to process pressure, temperature and in some cases the use of 
custom catalysts. In most cases, the Fischer-Tropsch process did not 
produce pure ethanol in the first pass through the system. Rather, a 
stream of mixed chemicals was produced, including gasoline, diesel, and 
oxygenated hydrocarbons (alcohol).\71\
---------------------------------------------------------------------------

    \71\ Gridley Ethanol Demonstration Project Utilizing Biomass 
Gasification Technology: Pilot Plant Gasifier and Syngas Conversion 
Testing, August 2002-June 2004; February 2005  NREL/SR-510-
37581; TSS Consultants, For the City of Gridley, California, 1617 
Cole Boulevard, Golden, Colorado 80401-3393, 303-275-3000  
http://www.nrel.gov; Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy by Midwest Research 
Institute  Battelle Contract No. DE-AC36-99-GO10337.
---------------------------------------------------------------------------

c. Plasma Technology
    The development of another technology, called plasma, is also 
underway for creating a syngas from which ethanol is produced. A plasma 
``reactor,'' generates an ionized gas (plasma) which serves as an 
electrical conductor to transfer intense radiant energy to a biomass or 
waste material. This intense energy is said to actually breakdown the 
various materials in the biomass or waste into their atomic components. 
Anything present in the feed-mass that doesn't gasify, is essentially 
``vitrified.'' This vitrified stream is reportedly inert and can be 
used as aggregate in paving materials. Following gasification, the 
syngas is cooled, impurities are removed, and the gas is sent to 
ethanol production as with the syngas platform described above.\72\
---------------------------------------------------------------------------

    \72\ Ethanol From Tires Via Plasma Converter Plus Fischer 
Tropsch, March 15, 2006; http://thefraserdomain.typepad.com/energy/2006/03/ethanol_from_ti.html
.

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

d. Feedstock Optimization
    Cellulosic biomass can come from a variety of sources. Because the 
conversion of cellulosic biomass to ethanol has not yet been 
commercially demonstrated, we cannot say at this time which feedstocks 
are superior to others. A few of the many resources are: Post-sorted 
municipal waste, rice and wheat straw,\73\ soft-woods, hardwood, switch 
grass, and bagasse. Regardless, each feedstock requires a specific 
combination of pretreatment methods and enzyme ``cocktails'' to 
optimize the operation and maximize the ethanol yield. One of the many 
challenges for the cellulose-ethanol industry is to find the best 
feedstocks and then develop the most cost-effective ways for converting 
them into ethanol.
---------------------------------------------------------------------------

    \73\ Wheat Straw for Ethanol Production in Washington: A 
Resource, Technical, and Economic Assessment, September 2001, 
WSUCEEP2001084; Prepared by: James D. Kerstetter, Ph.D., John Kim 
Lyons, Washington State University Cooperative Extension Energy 
Program, 925 Plum Street, SE., P.O. Box 43165, Olympia, WA 98504-
3165; Prepared for: Washington State Office of Trade and Economic 
Development.
---------------------------------------------------------------------------

3. Renewable Fuel Distribution System Capability
    Ethanol and biodiesel blended fuels are currently not shipped by 
petroleum product pipeline due to operational issues and additional 
cost factors. Hence, a separate distribution system is needed for 
ethanol and biodiesel up to the point where they are blended into 
petroleum-based fuel as it is loaded into tank trucks for delivery to 
retail and fleet operators. In cases where ethanol and biodiesel are 
produced within 200 miles of a terminal, trucking is often the 
preferred means of distribution. For longer shipping distances, the 
preferred

[[Page 23964]]

method of bringing renewable fuels to terminals is by rail and barge.
    Modifications to the rail, barge, tank truck, and terminal 
distribution systems will be needed to support the transport of the 
anticipated increased volumes of renewable fuels. These modifications 
include the addition of terminal blending systems for ethanol and 
biodiesel, additional storage tanks at terminals, additional rail 
delivery systems at terminals for ethanol and biodiesel, and additional 
rail cars, barges, and tank trucks to distribute ethanol and biodiesel 
to terminals. Terminal storage tanks for 100 percent biodiesel will 
also need to be heated during cold months to prevent gelling. The most 
comprehensive study of the infrastructure requirements for an expanded 
fuel ethanol industry was conducted for the Department of Energy (DOE) 
in 2002.\74\ The conclusions reached in that study indicate that the 
changes needed to handle the anticipated increased volume of ethanol by 
2012 will not represent a major obstacle to industry. While some 
changes have taken place since this report was issued, including an 
increased reliance on rail over marine transport, we continue to 
believe that the rail and marine transportation industries can manage 
the increased growth in demand in an orderly fashion. This belief is 
supported by the demonstrated ability for the industry to handle the 
rapid increases and redistribution of ethanol use across the country 
over the last several years as MTBE was removed. The necessary facility 
changes at terminals and at retail stations to dispense ethanol 
containing fuels have been occurring at a record pace. Given that 
future growth is expected to progress at a steadier pace and with 
greater advance warning in response to economic drivers, we anticipate 
that the distribution system will be able to respond appropriately. A 
discussion of the costs associated making the changes discussed above 
is contained in Section VII.B of today's preamble.
---------------------------------------------------------------------------

    \74\ ``Infrastructure Requirements for an Expanded Fuel Ethanol 
Industry,'' Downstream Alternatives Inc., January 15, 2002.
---------------------------------------------------------------------------

VII. Impacts on Cost of Renewable Fuels and Gasoline

    This section examines the impact on fuel costs resulting from the 
growth in renewable fuel use between a base year of 2004 and 2012. We 
note that based on analyses conducted by the Energy Information 
Administration (EIA), renewable fuels will be used in gasoline and 
diesel fuel in excess of the RFS requirements. As such, the changes in 
the use of renewable fuels and their related cost impacts are not 
directly attributable to the RFS rule. Rather, our analysis assesses 
the broader fuels impacts of the growth in renewable fuel use in the 
context of corresponding changes to the makeup of gasoline. These fuel 
impacts include the elimination of the reformulated gasoline (RFG) 
oxygen standard which has resulted in the refiners ceasing to use the 
gasoline blendstock methyl tertiary butyl ether (MTBE) and replacing it 
with ethanol. Thus, in this analysis, we are assessing the impact on 
the cost of gasoline and diesel fuel of increased use of renewable 
fuels, the cost savings resulting from the phase out of MTBE and the 
increased cost due to the other changes in fuel quality that result.
    As discussed in Section II, we chose to analyze a range of 
renewable fuel use. In the case of ethanol's use in gasoline, the lower 
end of this range is based on the minimum renewable fuel volume 
requirements in the Act, (the RFS case) and the higher end is based on 
AEO 2006 (the EIA case). At both ends of this range, we assume that 
biodiesel consumption will be the level estimated in AEO 2006. We 
analyzed the projected fuel consumption scenario and associated program 
costs in 2012, the year that the RFS is fully phased-in. The volumes of 
renewable fuels consumed in 2012 at the two ends of the range are 
summarized in Table II.A.1-1.
    We have estimated an average corn ethanol production cost of $1.26 
per gallon in 2012 (2004 dollars) for the RFS case and $1.32 per gallon 
for the EIA case. For cellulosic ethanol, we estimate it will cost 
approximately $1.65 in 2012 (2004 dollars) to produce a gallon of 
ethanol using corn stover as a cellulosic feedstock. In this analysis, 
however, we assume that the cellulosic requirement will be met by corn-
based ethanol produced by energy sourced from biomass (animal and other 
waste materials as discussed in Section III.B of today's preamble) and 
costing the same as corn based ethanol produced by conventional means.
    We estimated production costs for soy-derived biodiesel of $2.06 
per gallon in 2004 and $1.89 per gallon in 2012. For yellow grease 
derived biodiesel, we estimate an average production cost of $1.19 per 
gallon in 2004 and $1.11 in 2012.
    For the proposed rule, we estimated the cost of increased use of 
renewable fuel and other major cost impacts by developing our own cost 
spreadsheet model. That analysis considered the production cost, 
distribution cost as well as the cost for balancing the octane and RVP 
caused by these fuel changes. That analysis, however, could not 
properly balance octane and other gasoline qualities. For this final 
rule, we have therefore used the services of Jacobs Consultancy to run 
their refinery LP model to estimate the cost impacts of the RFS rule.
    The results from the refinery LP model indicate that the impacts on 
overall gasoline costs from the increased use of ethanol and the 
corresponding changes to the other aspects of gasoline would be 0.49 
cents per gallon for the RFS case. The EIA case would result in 
increased total cost of 1.03 cents per gallon. The actual cost at the 
fuel pump, however, will be decreased due to the effect of State and 
Federal tax subsidies for ethanol. Taking this into consideration 
results in ``at the pump'' decreased costs (cost savings) of -0.47 
cents per gallon for the RFS case and ``at the pump'' decreased cost of 
-0.83 cents per gallon for the EIA case. Section 7 of the RIA contains 
more detail on the cost analysis used to develop these costs.

A. Renewable Fuel Production and Blending Costs

1. Ethanol Production Costs
a. Corn Ethanol
    A significant amount of work has been done in the last decade on 
surveying and modeling the costs involved in producing ethanol from 
corn to serve business and investment purposes as well as to try to 
educate energy policy decisions. Corn ethanol costs for our work were 
estimated using a model developed by USDA in the 1990s that has been 
continuously updated by USDA. The most current version was documented 
in a peer-reviewed journal paper on cost modeling of the dry-grind corn 
ethanol process, and it produces results that compare well with cost 
information found in surveys of existing plants.75 76 We 
made some minor modifications to the USDA model to allow scaling of the 
plant size, to allow consideration of plant energy sources other than 
natural gas, and to adjust for energy prices in 2012, the year of our 
analysis.
---------------------------------------------------------------------------

    \75\ Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B., 
Industrial Crops and Products 23 (2006) 288-296.
    \76\ Shapouri, H., Gallagher, P., USDA's 2002 Ethanol Cost-of-
Production Survey (published July 2005).
---------------------------------------------------------------------------

    The cost of ethanol production is most sensitive to the prices of 
corn and the primary co-product, DDGS. Utilities, capital, and labor 
expenses also have an impact, although to a lesser extent. Corn 
feedstock minus DDGS sale credits

[[Page 23965]]

represents about 48% of the final per-gallon cost, while utilities, 
capital and labor comprise about 19%, 9%, and 6%, respectively. For 
this work, we used corn prices of $2.50/bu and $2.71/bu for the RFS and 
EIA cases, respectively, with corresponding DDGS prices at $83.35/ton 
and $85.16/ton (2004 dollars). These estimates are from modeling work 
done for this rulemaking using the Forestry and Agricultural Sector 
Optimization Model, which is described in more detail in Chapter 8 of 
the RIA. Energy prices were derived from historical data and projected 
to 2012 using EIA's AEO 2006. More details on how the ethanol 
production cost estimates were made can be found in Chapter 7 of the 
RIA.
    The estimated average corn ethanol production cost of $1.26 per 
gallon in 2012 (2004 dollars) in the RFS case and $1.32 per gallon in 
the EIA case represents the full cost to the plant operator, including 
purchase of feedstocks, energy required for operations, capital 
depreciation, labor, overhead, and denaturant, minus revenue from sale 
of co-products. It assumes that 86% of new plants will use natural gas 
as a thermal energy source, at a price of $6.16/MMBtu (2004 
dollars).\77\ It does not account for any subsidies on production or 
sale of ethanol. Note that the cost figure generated here is 
independent of the market price of ethanol, which has been related 
closely to the wholesale price of gasoline for the past 
decade.78 79
---------------------------------------------------------------------------

    \77\ For more details on fuel sources and costs of production, 
see RIA Chapter 1.2.2 and 7.1.1.2.
    \78\ Whims, J., Sparks Companies, Inc. and Kansas State 
University, ``Corn Based Ethanol Costs and Margins, Attachment 1'' 
(Published May 2002).
    \79\ Piel, W.J., Tier & Associates, Inc., March 9, 2006 report 
on costs of ethanol production and alternatives.
---------------------------------------------------------------------------

    Under the Energy Act, starch-based ethanol can be counted as 
cellulosic if at least 90% of the process energy is derived from 
renewable feedstocks, which include plant cellulose, municipal solid 
waste, and manure biogas.\80\ It is expected that the vast majority of 
the 250 million gallons per year of cellulosic ethanol production 
required by 2013 will be made using this provision. While we have been 
unable to develop a detailed production cost estimate for corn ethanol 
meeting cellulosic criteria, we assume that the costs will not be 
significantly different from conventionally produced corn ethanol. We 
believe this is reasonable because the costs of hauling, storing, and 
processing this low or zero cost waste material in order to combust it 
will be significant, thus making overall production costs at these 
plants similar to gas-fired ethanol plants. As of the time of this 
writing, we know of only a few operating plants of this type, and 
expect the quantity of ethanol produced this way to remain a relatively 
small fraction of the total ethanol demand. Thus, the sensitivity of 
the overall analysis to this assumption is also very small.\81\ Based 
on these factors, we have assigned starch ethanol made using this 
cellulosic criteria the same cost as ethanol produced from corn using 
conventional means.
---------------------------------------------------------------------------

    \80\ Energy Policy Act of 2005, Section 1501 amending Clean Air 
Act Section 211(o)(1)(A).
    \81\ See Table VI.A.1-2 for more details on number of operating 
ethanol plants and their fuel sources.
---------------------------------------------------------------------------

b. Cellulosic Ethanol
    In 1999, the National Renewable Energy Laboratory (NREL) published 
a report outlining its work with the USDA to design a computer model of 
a plant to produce ethanol from hard-wood chips.\82\ Although the model 
was originally prepared for hardwood chips, it was meant to serve as a 
modifiable-platform for ongoing research using cellulosic biomass as 
feedstock to produce ethanol. Their long-term plan was that various 
indices, costs, technologies, and other factors would be regularly 
updated.
---------------------------------------------------------------------------

    \82\ Lignocellulosic Biomass to Ethanol Process Design and 
Economics Utilizing Co-Current Dilute Acid Prehydrolysis and 
Enzymatic Hydrolysis Current and Futuristic Scenarios, Robert 
Wooley, Mark Ruth, John Sheehan, and Kelly Ibsen, Biotechnology 
Center for Fuels and Chemicals, Henry Majdeski and Adrian Galvez, 
Delta-T Corporation; National Renewable Energy Laboratory, Golden, 
CO, July 1999, NREL/TP-580-26157.
---------------------------------------------------------------------------

    NREL and USDA used a modified version of the model to compare the 
cost of using corn-grain with the cost of using corn stover to produce 
ethanol. We used the corn stover model from the second NREL/USDA study 
for the analysis for this rule. Because there were no operating plants 
that could potentially provide real world process design, construction, 
and operating data for processing cellulosic ethanol, NREL had 
considered modeling the plant based on assumptions associated with a 
first-of-a-kind or pioneer plant. The literature indicates that such 
models often underestimate actual costs since the high performance 
assumed for pioneer process plants is generally unrealistic.
    Instead, the NREL researchers assumed that the corn stover plant 
was an Nth generation plant, e.g., not a pioneer plant or first-or-its 
kind, built after the industry had been sufficiently established to 
provide verified costs. The corn stover plant was normalized to the 
corn kernel plant, e.g., placed on a similar basis.\83\ It is also 
reasonable to expect that the cost of cellulosic ethanol would be 
higher than corn ethanol because of the complexity of the cellulose 
conversion process. Recently, process improvements and advancements in 
corn production have considerably reduced the cost of producing corn 
ethanol. We also believe it is realistic to assume that cellulose-
derived ethanol process improvements will be made and that one can 
likewise reasonably expect that, as the industry matures, the cost of 
producing ethanol from cellulose will also decrease.
---------------------------------------------------------------------------

    \83\ Determining the Cost of Producing Ethanol from Corn Starch 
and Lignocellulosic Feedstocks; A Joint Study Sponsored by: USDA and 
USDOE, October 2000  NREL/TP-580-28893  Andrew 
McAloon, Frank Taylor, Winnie Yee, USDA, Eastern Regional Research 
Center Agricultural Research Service; Kelly Ibsen, Robert Wooley, 
National Renewable Energy Laboratory, Biotechnology Center for Fuels 
and Chemicals, 1617 Cole Boulevard, Golden, CO, 80401-3393; NREL is 
a USDOE Operated by Midwest Research Institute  Battelle 
 Bechtel; Contract No. DE-AC36-99-GO10337.
---------------------------------------------------------------------------

    We calculated fixed and variable operating costs using percentages 
of direct labor and total installed capital costs. Following this 
methodology, we estimate that producing a gallon of ethanol using corn 
stover as a cellulosic feedstock would cost $1.65 in 2012 (2004 
dollars).
2. Biodiesel Production Costs
    We based our estimate for the cost to produce biodiesel on the use 
of USDA's, NREL's and EIA's biodiesel computer models, along with 
estimates from engineering vendors that design biodiesel plants. 
Biodiesel fuel can be made from a wide variety of virgin vegetable oils 
such as canola, corn oil, cottonseed, etc. though, the operating costs 
(minus the costs of the feedstock oils) for these virgin vegetable oils 
are similar to the costs based on using soy oil as a feedstock, 
according to an analysis by NREL Biodiesel costs are therefore 
determined based on the use of soy oil, since this is the most commonly 
used virgin vegetable feedstock oil, and the use of recycled cooking 
oil (yellow grease) as a feedstock. Production costs are based on the 
process of continuous transesterification, which converts these 
feedstock oils to esters, along with the ester finishing processes and 
glycerol recovery. The models and vendors data are used to estimate the 
capital, fixed and operating costs associated with the production of 
biodiesel fuel, considering utility, labor, land and any other process 
and operating requirements, along with the prices for

[[Page 23966]]

feedstock oils, methanol, chemicals and the byproduct glycerol.
    The USDA, NREL and EIA models are based on a medium sized biodiesel 
plant that was designed to process raw degummed virgin soy oil as the 
feedstock. Additionally, the EIA model also contains a representation 
to estimate the biodiesel production cost for a plant that uses yellow 
grease as a feedstock. In the USDA model, the equipment needs and 
operating requirements for their biodiesel plant was estimated through 
the use of process simulation software. This software determines the 
biodiesel process requirements based on the use of established 
engineering relationships, process operating conditions and reagent 
needs. To substantiate the validity and accuracy of their model, USDA 
solicited feedback from major biodiesel producers. Based on responses, 
they then made adjustments to their model and updated their input 
prices to year 2005. The NREL model is also based on process simulation 
software, though the results are adjusted to reflect NREL's modeling 
methods, using prices based on year 2002. The output for all of these 
models was provided in spreadsheet format. We also use engineering 
vendor estimates as another source to generate soy oil and yellow 
grease biodiesel production costs. These firms are primarily engaged in 
the business of designing biodiesel plants.
    The production costs are based on an average biodiesel plant 
located in the Midwest using feedstock oils and methanol, which are 
catalyzed into esters and glycerol by use of sodium hydroxide. Because 
local feedstock costs, distribution costs, and biodiesel plant type 
introduce some variability into cost estimates, we believe that using 
an average plant to estimate production costs provides a reasonable 
approach. Therefore, we simplified our analysis and used costs based on 
an average plant and average feedstock prices since the total biodiesel 
volumes forecasted are not large and represent a small fraction of the 
total projected renewable volumes.
    The models and vendor estimates are further modified to use input 
prices for feedstocks, byproducts and energy that reflect the effects 
of the fuels provisions in the Energy Act. In order to capture a range 
of production costs, we generated cost projections from all of the 
models and vendors. We present the details on these estimates in 
Chapter 7 of the RIA.
    For soy oil biodiesel production, we estimate a production cost 
ranging from $1.89 to $2.15 per gallon in 2012 (in 2004 dollars) using 
these different models and sources of information. For yellow grease 
derived biodiesel, we used the EIA and vendor estimates to generate 
total production costs which range from $1.11 to $1.56 for year 2012.
    With the current Biodiesel Blender Tax Credit Program, producers 
using virgin vegetable oil stocks receive a one dollar per gallon tax 
subsidy while yellow grease producers receive 50 cents per gallon, 
reducing the net production cost to a range of 89 to 115 cents per 
gallon for soy oil and 61 to 106 cents per gallon for yellow greased 
derived biodiesel fuel in 2012. This compares favorably to the 
projected wholesale diesel fuel prices of 138 cents per gallon in 2012, 
signifying that the economics for biodiesel are positive under the 
effects of the blender credit program, though the tax credit program 
will expire in 2008 if it is not extended. Congress may later elect to 
extend the blender credit program following the precedence used for 
extending the ethanol blending subsidies. Additionally, the Small 
Biodiesel Blenders Tax credit program and state tax and credit programs 
offer some additional subsidies and credits, though the benefits are 
modest in comparison to the Blender's Tax credit.
3. Diesel Fuel Costs
    Biodiesel fuel is blended into highway and nonroad diesel fuel, 
which increases the volume and therefore the supply of diesel fuel and 
thereby reduces the demand for refinery-produced diesel fuel. In this 
section, we estimate the overall cost impact, considering how much 
refinery based diesel fuel is displaced by the forecasted production 
volume of biodiesel fuel. The cost impacts are evaluated considering 
the production cost of biodiesel with and without the subsidy from the 
Biodiesel Blenders Tax credit program. Additionally, the diesel cost 
impacts are quantified with refinery diesel prices as forecasted by 
Jacob's which is based on EIA's AEO 2006.
    We estimate the net effect that biodiesel production has on overall 
cost for diesel fuel in year 2012 using total production costs for 
biodiesel and diesel fuel. The costs are evaluated based on how much 
refinery based diesel fuel is displaced by the biodiesel volumes as 
forecasted by EIA, accounting for energy density differences between 
the fuels. The cost impact is estimated from a 2004 year basis, by 
multiplying the production costs of each fuel by the respective changes 
in volumes for biodiesel and estimated displaced diesel fuel. We 
further assume that all of the forecasted biodiesel volume is used as 
transport fuel, neglecting minor uses in the heating oil market.
    For RFS cases, the net effect of biodiesel production on diesel 
fuel costs, including the biodiesel blenders' subsidy, is a reduction 
in the cost of transport diesel fuel costs by $114 million per year, 
which equates to a reduction in fuel cost of about 0.20 cents per 
gallon.\84\ Without the subsidy, the transport diesel fuel costs are 
increased by $91 million per year, or an increase of 0.16 cents per 
gallon for transport diesel fuel.
---------------------------------------------------------------------------

    \84\ Based on EIA's AEO 2006, 58.9 billion gallons of highway 
and off-road diesel fuel is projected to be consumed in 2012.
---------------------------------------------------------------------------

B. Distribution Costs

1. Ethanol Distribution Costs
    There are two components to the costs associated with distributing 
the volumes of ethanol necessary to meet the requirements of the 
Renewable Fuels Standard (RFS): (1) The capital cost of making the 
necessary upgrades to the fuel distribution infrastructure system, and 
(2) the ongoing additional freight costs associated with shipping 
ethanol to terminals. The most comprehensive study of the 
infrastructure requirements for an expanded fuel ethanol industry was 
conducted for the Department of Energy (DOE) in 2002.\85\ That study 
provided the foundation for our estimates of the capital costs 
associated with upgrading the distribution infrastructure system as 
well as the freight costs to handle the increased volume of ethanol 
needed to meet the requirements of the RFS in 2012. Distribution costs 
are evaluated here for both the RFS case and for the EIA case. The 2012 
reference case against which we are estimating the cost of distributing 
the additional volume of ethanol needed to meet the requirements of the 
RFS is 3.9 billion gallons.
---------------------------------------------------------------------------

    \85\ Infrastructure Requirements for an Expanded Fuel Ethanol 
Industry, Downstream Alternatives Inc., January 15, 2002.
---------------------------------------------------------------------------

a. Capital Costs To Upgrade Distribution System for Increased Ethanol 
Volume
    The 2002 DOE study examined two cases regarding the use of 
renewable fuels for estimating the capital costs for distributing 
additional ethanol. The first assumed that 5.1 billion gal/yr of 
ethanol would be used in 2010, and the second assumed that 10 billion 
gal/yr of ethanol would be used in the 2015 timetable. We interpolated 
between these two cases to provide the foundation for our estimate of 
the capital costs to support the use of 6.7 billion gal/yr of ethanol 
in 2012 for the

[[Page 23967]]

RFS case.\86\ The 10 billion gal/yr case examined in the DOE study was 
used as the foundation in estimating the capital costs under the EIA 
projected case examined in today's rule of 9.6 billion gal/yr of 
ethanol.\87\ Our estimated capital costs in this final rule differ from 
those in the proposed rule for several reasons. We adjusted our capital 
costs from those in the proposal to reflect an increase in the cost of 
tank cars and barges used to ship ethanol since the DOE study was 
conducted. In addition, we are assuming an increased reliance on rail 
transport over that projected in the DOE study.\88\
---------------------------------------------------------------------------

    \86\ See chapter 7.3 of the Regulatory Impact Analysis 
associated with today's rule for additional discussion of how the 
results of the DAI study were adjusted to reflect current conditions 
in estimating the ethanol distribution infrastructure capital costs 
under today's rule.
    \87\ For both the 6.7 bill gal/yr and 9.6 bill gal/yr cases, the 
baseline from which the DOE study cases were projected was adjusted 
to reflect a 3.9 bill gal/yr 2012 baseline.
    \88\ This increased reliance on rail transport was the subject 
of a sensitivity analysis conducted for the proposed rule.
---------------------------------------------------------------------------

    Table VII.B.1.a-1contains our estimates of the infrastructure 
changes and associated capital costs for the two ethanol use scenarios 
examined in today's rule. Amortized over 15 years with a 7 percent cost 
of capital, the total capital costs equate to approximately 1.4 cents 
per gallon of ethanol under the RFS case and 1.2 cents per gallon under 
the EIA case.\89\
---------------------------------------------------------------------------

    \89\ These capital costs will be incurred incrementally during 
the period of 2007-2012 as ethanol volumes increase. For the purpose 
of this analysis, we assumed that all capital costs were incurred in 
2007.

    Table VII.B.1.A-1.--Estimated Ethanol Distribution Infrastructure
                          Capital Costs ($M) *
------------------------------------------------------------------------
                                                  RFS case     EIA case
                                                6.7 Bgal/yr  9.6 Bgal/yr
------------------------------------------------------------------------
Fixed Facilities:
  Retail......................................           20           44
  Terminals...................................          115          241
Mobile Facilities:
  Transport Trucks............................           24           50
  Barges......................................           21           43
  Rail Cars...................................          172          297
                                               -------------------------
    Total Capital Costs.......................          352         675
------------------------------------------------------------------------
* Relative to a 3.9 billion gal/yr reference case.

b. Ethanol Freight Costs
    The Energy Information Administration (EIA) translated the ethanol 
freight cost estimates in the DOE study to a census division basis.\90\ 
For this final rule, we translated the EIA projections into State-by-
State and national average freight costs to align with our State-by-
State ethanol use estimates. Not including capital recovery, we 
estimate that the freight cost to transport ethanol to terminals would 
range from 4 cents per gallon in the Midwest to 25 cents per gallon to 
the West Coast. On a national basis, this averages to 11.3 cents per 
gallon of ethanol under the RFS case and 11.9 cents per gallon under 
the EIA case.\91\ We adjusted the estimated ethanol freight costs from 
those in the proposal by increasing the cost of shipping ethanol to 
satellite versus hub terminals, by increasing the cost of gathering 
ethanol for large volume shipments to hub terminals, and by increasing 
the percentage of ethanol delivered to large volume terminals versus 
the volume delivered to lesser volume terminals.\92\
---------------------------------------------------------------------------

    \90\ Petroleum Market Model of the National Energy Modeling 
System, Part 2, March 2006, DOE/EIA-059 (2006), http://tonto.eia.doe.gov/FTPROOT/modeldoc/m059
(2006)-2.pdf.

    \91\ See Chapter 7.3 of the RIA.
    \92\ Hub terminals refer to those terminals where ethanol is 
delivered in large volume shipments such as by unit train 
(consisting of 70 tank cars or more) or marine barges/tanker. 
Satellite terminals are those terminals that are either supplied 
from a hub terminal or receive ethanol shipments in smaller 
quantities directly from the producer. See Chapter 7 of the RIA 
regarding how these estimates were adjusted from those in the 
proposal and the check of our estimates against current ethanol 
freight rates.
---------------------------------------------------------------------------

    Including the cost of capital recovery for the necessary 
distribution facility changes, we estimate the national average cost of 
distributing ethanol to be 12.7 cents per gallon under the RFS case and 
13.1 cents per gallon under the EIA case.\93\ Thus, we estimate the 
total cost for producing and distributing ethanol to be between $1.39 
and $1.45 per gallon of ethanol, on a nationwide average basis. This 
estimate includes both the capital costs to upgrade the distribution 
system and freight costs.
---------------------------------------------------------------------------

    \93\ All capital costs were assumed to be incurred in 2007 and 
were amortized over 15 years at a 7 percent cost of capital.
---------------------------------------------------------------------------

2. Biodiesel Distribution Costs
    The volume of biodiesel used by 2012 under the RFS is estimated at 
300 million gallons per year. The 2012 baseline case against which we 
are estimating the cost of distributing the additional volume of 
biodiesel is 30 million gallons.\94\
---------------------------------------------------------------------------

    \94\ 2004 baseline of 25 million gallons grown with diesel 
demand to 2012.
---------------------------------------------------------------------------

    The capital costs associated with distribution of biodiesel are 
higher per gallon than those associated with the distribution of 
ethanol due to the need for storage tanks, blending systems, barges, 
tanker trucks and rail cars to be insulated and in many cases heated 
during the winter months.\95\ In the proposal, we estimated that these 
capital costs would be approximately $50,000,000. We adjusted our 
estimate of these capital costs for this final rule based on additional 
information regarding the cost to install necessary storage and 
blending equipment at terminals and the need for additional rail tank 
cars for biodiesel.\96\ As discussed in the RIA, we now estimate that 
handling the increased biodiesel volume will require a total capital 
cost investment of $145,500,000 which equates to about 6 cents per 
gallon of new biodiesel volume.\97\
---------------------------------------------------------------------------

    \95\ See Chapter 1.3 of the Regulatory Impact Analysis 
associated with today's rule for a discussion of the special 
handling requirements for biodiesel under cold conditions.
    \96\ Biodiesel rail tank cars typically have a capacity of 
25,500 gallons as opposed to 30,000 gallons for an ethanol tank car. 
Thus, additional tank cars are needed to transport a given volume of 
biodiesel relative to the same volume of ethanol.
    \97\ Capital costs will be incurred incrementally over the 
period of 2007-2012 as biodiesel volumes increase. For the purpose 
of this analysis, all capital costs were assumed to be incurred in 
2007 and were amortized over 15 years at a 7 percent cost of 
capital.
---------------------------------------------------------------------------

    In the proposal, we estimated that the freight costs for ethanol 
may adequately reflect those for biodiesel as well. In response to 
comments, we sought additional information regarding the freight costs 
for biodiesel. This information indicates that freight costs for 
biodiesel are typically 30 percent higher than those for ethanol which 
translates into an estimate of 15.5 cents per gallon for biodiesel 
freight costs on a national average basis.\98\
---------------------------------------------------------------------------

    \98\ The estimated ethanol freight costs were increased by 30 
percent to arrive at the estimate of biodiesel freight costs.
---------------------------------------------------------------------------

    Including the cost of capital recovery for the necessary 
distribution facility changes, we estimate the cost of distributing 
biodiesel to be 21.5 cents per gallon. Depending on whether the 
feedstock is waste grease or virgin oil, we estimate the total cost for 
producing and distributing biodiesel to be between $1.33 and $2.11 per 
gallon of biodiesel, on a nationwide average basis.\99\ This estimate 
includes both the capital costs to upgrade the distribution system and 
freight costs, and the wide range reflects differences in different 
types of production feedstocks.
---------------------------------------------------------------------------

    \99\ See Section VII.A.2. of this preamble regarding biodiesel 
production costs. We estimated 2012 production costs of $1.89 per 
gal for soy-derived biodiesel and $1.11 per gal for yellow grease 
derived biodiesel.
---------------------------------------------------------------------------

C. Estimated Costs to Gasoline

    To estimate the cost of increased use of renewable fuels, the cost 
savings from the phase out of MTBE and the production cost of alkylate, 
we relied on

[[Page 23968]]

refinery modeling conducted by Jacob's Consultancy that established 
baselines based on 2004 volumes, which were then used to project a 
reference case and 2 control cases for 2012. The contractor developed a 
five region, U.S. demand model in which specific regional clean product 
demands are sold at hypothetical regional terminals.
1. Description of Cases Modeled
a. Base Case (2004)
    The baseline case was established by modeling fuel volumes for 
2004, with data on fuel properties provided to the contractor by EPA. 
Fuel property data for this base case was built off of 2004 refinery 
batch reports provided to EPA; however, the base case assumed sulfur 
standards based on gasoline data in 2004, not with fully phased in Tier 
2 gasoline standards at the 30 ppm level. In addition we assumed the 
phase-in of 15 ppm sulfur standards for highway, nonroad, locomotive 
and marine diesel fuel. The supply/demand balance for the U.S. was 
based on gasoline volumes from EIA and the California Air Resources 
Board (CARB). Our decision to use 2004 rather than 2005 as the baseline 
year was because of the refinery upset conditions associated with the 
Gulf Coast hurricanes in 2005.
b. Reference Case (2012)
    The reference case was based on modeling the base case, using 2012 
fuel prices, and scaling the 2004 fuel volumes to 2012 based on growth 
in fuel demand. In addition, we scaled MTBE and ethanol upward, in 
proportion to gasoline growth, and assumed the RFS program would not be 
in effect. For example, if the PADD 1 gasoline pool MTBE oxygen was 0.5 
wt% in 2004, the reference case assumed it should remain at 0.5 wt%. 
Finally, we assumed the MSAT 1 standards would remain in place as would 
the RFG oxygen mandate. We assumed the crude slate quality in 2012 is 
the same as the baseline case.
c. Control Cases (2012)
    Two control cases were run for 2012. The assumptions for each of 
the control cases are summarized below
    Control Case 1 (RFS case): 6.7 billion gallons/yr (BGY) of ethanol 
in gasoline; it reflects the renewable fuel mandate. We have also 
assumed that 0.3 billion gallons of biodiesel will be consumed as 
reflected in Table II.A.1-1. In addition, it is assumed that no MTBE is 
in gasoline, MSAT1 is in place, the psi waiver for conventional 
gasoline containing 10 volume percent ethanol is in effect, the RFS is 
in effect, and there is no RFG oxygenate mandate.
    Control Case 2 (EIA case): Same as Control Case 1, except the 
ethanol volume in gasoline is 9.6 BGY.
2. Overview of Cost Analysis Provided by the Contractor Refinery Model
    The estimated cost of increased use of renewable fuels, the cost 
savings from the phase out of MTBE and the cost of converting some of 
the former MTBE feedstocks to produce alkylate, isooctane, and 
isooctene is provided by the output of the refinery model. As described 
in VII.C.1, the cost analysis was conducted by comparing the 2012 
reference case with the two control cases which are assumed to take 
place in 2012.
    The major factors which impact the costs in the refinery model are 
(1) blending in more ethanol, (2) adjusting the gasoline blending to 
lower RVP, (3) removing the MTBE, (4) converting MTBE feedstocks to 
other high quality replacement, and (5) adjusting for the change in 
gasoline energy density. The first is the addition of ethanol to the 
gasoline pool. The refinery model estimates the cost impact of 
increasing the volume of ethanol in the reference case from 3.94 
billion gallons to 6.67 and 9.60 billion gallons in the RFS and EIA 
modeled cases, respectively. The estimated production prices for 
ethanol for the RFS and EIA cases are provided above in Section VII.A. 
We also show the results with the federal and state subsidies applied 
to the production price of ethanol.
    The addition of ethanol to wintertime gasoline, and to summertime 
RFG, will cause an increase of approximately 1 psi in RVP which needs 
to be offset to maintain constant RVP levels. One method that refiners 
could choose to offset the increase in RVP is to reduce the butane 
levels in their gasoline. To some extent, the modeling results showed 
some occurrences of that, but it also did not report an overall 
increase in butane sales as a result of the increased use of ethanol.
    To convert the captive MTBE over to alkylate, after the rejection 
of methanol, refiners will need to combine refinery-produced isobutane 
with the isobutylene that was used as a feedstock for MTBE. The use of 
the isobutane will reduce the RVP of the gasoline pool from which it 
comes, helping to offset the RVP impacts of ethanol. Also, the 
increased production of alkylate provides a low RVP gasoline blendstock 
which offsets a portion of the cracked stocks produced by the fluidized 
catalytic cracker unit. Other means that the refinery model used to 
offset the high blending RVP of ethanol included purchasing gasoline 
components with lower RVP, producing more poly gasoline which has low 
RVP and selling more high-RVP naphtha to petrochemical sales.
3. Overall Impact on Fuel Cost
    Based on the refinery modeling conducted for today's rule, we have 
calculated the costs of these fuels changes that will occur for the RFS 
and EIA cases. The costs are expressed two different ways. First, we 
express the cost of the program without the ethanol consumption 
subsidies in which the costs are based on the total accumulated cost of 
each of the fuels changes. Second, we express the cost with the ethanol 
consumption subsidies included since the subsidized portion of the 
renewable fuels costs will not be represented to the consumer in its 
fuels costs paid at the pump, but instead by being paid through the 
state and federal tax revenues. In all cases, the capital costs are 
amortized at 7 percent return on investment (ROI), and based on 2006 
dollars.
a. Cost Without Ethanol Subsidies
    Table VII.C.3.a-1 summarizes the costs without ethanol subsidies 
for each of the two control cases, including the cost for each aspect 
of the fuel changes, and the aggregated total and the per-gallon costs 
for all the fuel changes.\100\ This estimate of costs reflects the 
changes in gasoline that are occurring with the expanded use of 
ethanol, including the corresponding removal of MTBE. These costs 
include the labor, utility and other operating costs, fixed costs and 
the capital costs for all the fuel changes expected. The per-gallon 
costs are derived by dividing the total costs over all U.S. gasoline 
projected to be consumed in 2012. We excluded federal and state ethanol 
consumption subsidies which avoids the transfer payments caused by 
these subsidies that would hide a portion of the program's costs.
---------------------------------------------------------------------------

    \100\ EPA typically assesses social benefits and costs of a 
rulemaking. However, this analysis is more limited in its scope by 
examining the average cost of production of ethanol and gasoline 
without accounting for the effects of farm subsidies that tend to 
distort the market price of agricultural commodities.

[[Page 23969]]



                    Table VII.C.3.A-1.--Estimated Cost Without Ethanol Consumption Subsidies
                         [Million dollars and cents per gallon; 7% ROI and 2006 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                   RFS case 6.8    EIA case 9.6    EIA case 9.6
                                                                   billion gals    billion gals    billion gals
                                                                  incremental to  incremental to  incremental to
                                                                  reference case  reference case     RFS case
----------------------------------------------------------------------------------------------------------------
Capital Costs ($MM).............................................          -5,878          -7,311          -1,433
Amortized Capital Costs ($MM/yr)................................            -647            -804            -158
Fixed Operating Cost ($MM/yr)...................................            -178            -222             -43
Variable Operating Cost ($MM/yr)................................            -201            -491            -290
Fuel Economy Cost ($MM/yr)......................................           1,848           3,255            1407
    Total Cost ($MM/yr).........................................             823            1739             915
Capital Costs (c/gal of gasoline)...............................           -0.40           -0.49           -0.10
Fixed Operating Cost (c/gal of gasoline)........................           -0.11           -0.14           -0.03
Variable Operating Cost (c/gal of gasoline).....................           -0.12           -0.30           -0.18
Fuel Economy Cost (c/gal of gasoline)...........................            1.13            1.98            0.86
    Total Cost Excluding Subsidies (c/gal of gasoline)..........            0.50            1.06            0.56
----------------------------------------------------------------------------------------------------------------

    Our analysis shows that when considering all the costs associated 
with these fuel changes resulting from the expanded use of subsidized 
ethanol that these various possible gasoline use scenarios will 
increase fuel costs by $820 million or $1,740 million in the year 2012 
for the RFS and EIA cases, respectively. Expressed as per-gallon costs, 
these fuel changes would increase fuel costs by 0.50 to 1.1 cents per 
gallon of gasoline.
b. Gasoline Costs Including Ethanol Consumption Tax Subsidies
    Table VII.C.3.b-1 expresses the total and per-gallon gasoline costs 
for the two control scenarios with the federal and state ethanol 
subsidies included. The federal tax subsidy is 51 cents per gallon for 
each gallon of new ethanol blended into gasoline. The state tax 
subsidies apply in 5 states and range from 1.6 to 29 cents per gallon. 
The cost reduction to the fuel industry and consumers is estimated by 
multiplying the subsidy times the volume of new ethanol estimated to be 
used in the state. The per-gallon costs are derived by dividing the 
total costs over all U.S. gasoline projected to be consumed in 2012.

                   Table VII.C.3.B-1.--Estimated Cost Including Ethanol Consumption Subsidies
                         [Million dollars and cents per gallon; 7% ROI and 2006 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                   RFS case 6.8    EIA case 9.6    EIA case 9.6
                                                                   billion gals    billion gals    billion gals
                                                                  incremental to  incremental to  incremental to
                                                                  reference case  reference case     RFS case
----------------------------------------------------------------------------------------------------------------
Total Cost ($MM/yr).............................................             823            1739             915
Federal Subsidy ($MM/yr)........................................           -1376           -2865           -1489
State Subsidies ($MM/yr)........................................              -5             -31             -26
    Revised Total Cost ($MM/yr).................................            -558           -1158            -600
Per-Gallon Cost Excluding Subsidies (c/gal of gasoline).........            0.50            1.06            0.56
Federal Subsidy (c/gal of gasoline).............................           -0.84           -1.74           -0.90
State Subsidies (c/gal of gasoline).............................          -0.003           -0.02           -0.02
    Total Cost Including Subsidies (c/gal of gasoline)..........           -0.34           -0.71           -0.37
----------------------------------------------------------------------------------------------------------------

    The cost including subsidies better represents gasoline's 
production cost as reflected to the fuel industry as a whole and to 
consumers ``at the pump'' because the federal and state subsidies tend 
to hide a portion of the actual costs. Our analysis estimates that the 
fuel industry and consumers will see a 0.34 and 0.71 cent per gallon 
decrease in the apparent cost of producing gasoline for the RFS and EIA 
cases, respectively.

VIII. What Are the Impacts of Increased Ethanol Use on Emissions and 
Air Quality?

    In this section, we evaluate the impact of increased production and 
use of renewable fuels on emissions and air quality in the U.S., 
particularly ethanol and biodiesel. In performing these analyses, we 
compare the emissions which would have occurred in the future if fuel 
quality had remained unchanged from pre-Act levels to those which will 
be either required under the Energy Policy Act of 2005 (Energy Act or 
the Act) or exist due to market forces.
    This approach differs from that traditionally taken in EPA 
regulatory impact analyses. Traditionally, we would have compared 
future emissions with and without the requirement of the Energy Act. 
However, as described in Section II, we expect that total renewable 
fuel use in the U.S. in 2012 to exceed the Act's requirements even in 
the absence of the RFS program. Thus, a traditional regulatory impact 
analysis would have shown no impact on emissions or air quality. This 
is because, strictly speaking, if the same volume and types of 
renewable fuels are produced and used with and without the RFS program, 
the RFS program has no impact on fuel quality and thus, no impact on 
emissions or air quality. However, levels of renewable fuel use are 
increasing dramatically relative to both today and the recent past, 
with corresponding impacts on emissions and air quality. We believe 
that it is appropriate to evaluate these changes here, regardless of 
whether they are occurring due to economic forces or Energy Act 
requirements.
    In the process of estimating the impact of increased renewable fuel 
use, we also include the impact of reduced use of MTBE in gasoline. It 
is the

[[Page 23970]]

increased production and use of ethanol which is facilitating the 
continued production of RFG which meets both commercial and EPA 
regulatory specifications without the use of MTBE. Because of this 
connection, we found it impractical to isolate the impact of increased 
ethanol use from the removal of MTBE.

A. Effect of Renewable Fuel Use on Emissions

1. Emissions From Gasoline Fueled Motor Vehicles and Equipment
    Several models of the impact of gasoline quality on motor vehicle 
emissions have been developed since the early 1990's. We evaluated 
these models and selected those which were based on the most 
comprehensive set of emissions data and developed using the most 
advanced statistical tools for this analysis. Still, as will be 
described below, significant uncertainty exists as to the effect of 
these gasoline components on emissions from both motor vehicle and 
nonroad equipment, particularly from the latest vehicle and engine 
models equipped with the most advanced emission controls. Pending 
adequate funding, we plan to conduct significant vehicle and equipment 
testing over the next several years to improve our estimates of the 
impact of these additives and other gasoline properties on emissions. 
We hope that the results from these test programs will be available for 
reference in the future evaluations of the emission and air quality 
impacts of U.S. fuel programs required by the Act.\101\
---------------------------------------------------------------------------

    \101\ Subject to funding.
---------------------------------------------------------------------------

    The remainder of this sub-section is divided into three parts. The 
first evaluates the impact of increased ethanol use and decreased MTBE 
use on gasoline quality. The second evaluates the impact of increased 
ethanol use and decreased MTBE use on motor vehicle emissions. The 
third evaluates the impact of increased ethanol use and decreased MTBE 
use on nonroad equipment emissions.
a. Gasoline Fuel Quality
    For the final rulemaking, we estimate the impact of increased 
ethanol use and decreased MTBE use on gasoline quality using refinery 
modeling conducted specifically for the RFS rulemaking.\102\ In 
general, adding ethanol to gasoline reduces the aromatic content of 
conventional gasoline and the mid- and high-distillation temperatures 
(e.g., T50 and T90). RVP increases except in areas where ethanol blends 
are not provided a 1.0 RVP waiver of the applicable RVP standards in 
the summer. With the exception of RVP, adding MTBE directionally 
produces the same impacts. Thus, the effect of removing MTBE results in 
essentially the opposite impacts. Neither oxygenate is expected to 
affect sulfur levels, as refiners control sulfur independently in order 
to meet the Tier 2 sulfur standards.
---------------------------------------------------------------------------

    \102\ Refinery modeling performed in support of the original RFG 
rulemaking is also used to help separate the effects of the two 
oxygenates.
---------------------------------------------------------------------------

    The impacts of oxygenate use are smaller with respect to RFG. This 
is due to RFG's VOC and toxics emission performance specifications, 
which limit the range of feasible fuel quality values. Thus, oxygenate 
type or level does not consistently affect the RVP level and aromatic 
and benzene contents of RFG.
    Table VIII.A.1.a-1 shows the fuel quality of a typical summertime, 
non-oxygenated conventional gasoline and how these qualities change 
with the addition of 10 volume percent ethanol. Similarly, the table 
shows the fuel quality of a typical MTBE RFG blend and how fuel quality 
might change with either ethanol use or simply MTBE removal. All of 
these fuels are based, in whole or in part, on projections made by 
Jacobs in their recent refinery modeling performed for EPA and 
therefore, represent improvements over the projections made for the 
NPRM. Please see Chapter 2 of the RIA for a detailed description of the 
methodologies used to determine the specific changes in projected fuel 
quality. As discussed there, we use the Jacobs model projections of RFG 
fuel quality directly in our emission modeling. For conventional 
gasoline, we use the Jacobs modeling described in Section VII to 
determine the change in fuel quality due to ethanol use and apply this 
change to base fuel quality estimates contained in EPA's NMIM emission 
inventory model. Sulfur is not shown in Table VIII.A.1.a-1, as it is 
held constant at 30 ppm, which is the average Tier 2 sulfur standard 
applicable to all gasoline sold in the U.S. in the timeframe of our 
emission analyses.

                              Table VIII.A.1.A-1.--Typical Summertime Fuel Quality
----------------------------------------------------------------------------------------------------------------
                                                   Conventional gasoline         Reformulated gasoline \a\
                                                ----------------------------------------------------------------
                 Fuel parameter                                                                          Non-
                                                  Typical 9     Ethanol     MTBE blend    Ethanol     oxygenated
                                                     RVP         blend                     blend        blend
----------------------------------------------------------------------------------------------------------------
RVP (psi)......................................          8.7          9.7          7.0          7.0          7.0
T50............................................          218          205          179          184          175
T90............................................          332          329          303          335          309
E200...........................................           41           50           60           58           52
E300...........................................           82           82           89           82           88
Aromatics (vol%)...............................           32           27           20           20           20
Olefins (vol%).................................          7.7          7.7            4           14           15
Oxygen (wt%)...................................            0          3.5          2.1          3.5            0
Benzene (vol%).................................          1.0          1.0         0.74         0.70        0.72
----------------------------------------------------------------------------------------------------------------
\a\ MTBE blend--Reference Case PADD 1 South, Ethanol blend--RFS Case PADD 1 North, Non-oxy blend. -RFS Case PADD
  1 South.

b. Emissions From Motor Vehicles
    We use the EPA Predictive Models to estimate the impact of gasoline 
fuel quality on exhaust VOC and NOX emissions from motor 
vehicles. These models were developed in 2000, in support of EPA's 
response to California's request for a waiver of the RFG oxygen 
mandate. These models represent a significant update of the EPA Complex 
Model. However, they are still based on emission data from Tier 0 
vehicles (roughly equivalent to 1990 model year vehicles). We based our 
estimates of the impact of fuel quality on CO emissions on the EPA 
MOBILE6.2 model. We base our estimates of the impact of fuel quality

[[Page 23971]]

on exhaust toxic emissions (benzene, formaldehyde, acetaldehyde, and 
1,3-butadiene) primarily on the MOBILE6.2 model, updated to reflect the 
effect of fuel quality on exhaust VOC emissions per the EPA Predictive 
Models. Very limited data are available on the effect of gasoline 
quality on PM emissions. Therefore, the effect of increased ethanol use 
on PM emissions can only be qualitatively discussed.
    In responding to California's request for a waiver of the RFG 
oxygen mandate in 2000, we found that both very limited and conflicting 
data were available on the effect of fuel quality on exhaust emissions 
from Tier 1 and later vehicles.\103\ Thus, we assumed at the time that 
changes to gasoline quality would not affect VOC, CO and NOX 
exhaust emissions from these vehicles.\104\ Very little additional data 
have been collected since that time on which to modify this assumption. 
Consequently, for our primary analysis for today's final rule we have 
maintained the assumption that changes to gasoline do not affect 
exhaust emissions from Tier 1 and later technology vehicles.
---------------------------------------------------------------------------

    \103\ The one exception was the impact of sulfur on emissions 
from these later vehicles, which is not an issue here due to the 
fact that renewable fuel use is not expected to change sulfur levels 
significantly.
    \104\ An exception is that MOBILE6.2 applies the effect of 
oxygenate on CO emissions to Tier 1 and later vehicles which are 
expected to be high emitters based on their age and mileage.
---------------------------------------------------------------------------

    For the NPRM, we evaluated one recent study by the Coordinating 
Research Council (CRC) which assessed the impact of ethanol and two 
other fuel properties on emissions from twelve 2000-2004 model year 
vehicles (CRC study E-67). Based on comments received on the NPRM, we 
evaluated four additional studies of the fuel-emission effects of 
recent model year vehicles. The results of these test programs indicate 
that emissions from these late model year vehicles are likely sensitive 
to changes in fuel properties. However, both the size and direction of 
the effects are not consistent between the various studies. More 
testing is still needed before confident predictions of the effect of 
fuel quality on emissions from these vehicles can be made.
    In the NPRM, we developed two sets of assumptions regarding the 
effect of fuel quality on emissions from Tier 1 and later vehicles to 
reflect this uncertainty. A primary analysis assumed that exhaust 
emissions from Tier 1 and later vehicles are not sensitive to fuel 
quality. This is consistent with our analysis of California's request 
for a waiver of the RFG oxygen mandate. A sensitivity analysis assumed 
that the NMHC and NOX emissions from Tier 1 and later 
vehicles were as sensitive to fuel quality as Tier 0 vehicles. Only one 
effect of fuel quality on CO emissions was assumed, that contained in 
EPA's MOBILE6.2 emission inventory model.
    The five available studies of Tier 1 and later vehicles support 
continuing this approach for exhaust NMHC and NOX emissions. 
The assumptions supporting both our primary and sensitivity analyses 
reasonably bracket the results of the five studies. However, we have 
decided to perform a sensitivity analysis for CO emissions, as well. In 
this case, we apply the fuel-emission effects from MOBILE6.2 for Tier 0 
vehicles to Tier 1 and later vehicles. This is analogous to the 
approach taken for exhaust NMHC and NOX emissions.
    We base our estimates of fuel quality on non-exhaust VOC and 
benzene emissions on the EPA MOBILE6.2 model. The one exception to this 
is the effect of ethanol on permeation emissions through plastic fuel 
tanks and elastomers used in fuel line connections. Recent testing has 
shown that ethanol increases permeation emissions, both by permeating 
itself and increasing the permeation of other gasoline components. This 
effect was included in EPA's analysis of California's most recent 
request for a waiver of the RFG oxygen requirement, but is not in 
MOBILE6.2.\105\ Therefore, we have added the effect of ethanol on 
permeation emissions to MOBILE6.2's estimate of non-exhaust VOC 
emissions in assessing the impact of gasoline quality on these 
emissions.
---------------------------------------------------------------------------

    \105\ For more information on California's request for a waiver 
of the RFG oxygen mandate and the Decision Document for EPA's 
response, see http://www.epa.gov/otaq/rfg_regs.htm#waiver.

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

    No models are available which address the impact of gasoline 
quality on PM emissions. Very limited data indicate that ethanol 
blending might reduce exhaust PM emissions under very cold weather 
conditions (e.g., -20 [deg]F to 0 [deg]F). Very limited testing at 
warmer temperatures (e.g., 20 [deg]F to 75 [deg]F) shows no definite 
trend in PM emissions with oxygen content. Thus, for now, no 
quantitative estimates can be made regarding the effect of ethanol use 
on direct PM emissions.
    Table VIII.A.1.b-1 presents the average per vehicle (2012 fleet) 
emission impacts of three types of RFG: Non-oxygenated, a typical MTBE 
RFG as has been marketed in the Gulf Coast, and a typical ethanol RFG 
which has been marketed in the Midwest.

  Table VIII.A.1.B-1.--Effect of RFG on Per Mile Emissions From Tier 0 Vehicles Relative to a Typical 9psi RVP
                                             Conventional Gasoline a
----------------------------------------------------------------------------------------------------------------
                                                                                         11 Volume    10 Volume
                 Pollutant                              Source             Non-Oxy RFG    percent      percent
                                                                            (percent)       MTBE       ethanol
----------------------------------------------------------------------------------------------------------------
                                                Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC.......................................  EPA Predictive Models........        -13.4        -15.3         -9.7
NOX.......................................                                        -2.4         -1.7          7.3
CO........................................  MOBILE6.2....................          -22          -31          -36
Exhaust Benzene...........................  EPA Predictive and Complex           -21.2        -29.7        -38.9
                                             Models.
Formaldehyde..............................                                        -5.9         19.4          2.3
Acetaldehyde..............................                                        -0.2         -9.5        173.7
1,3-Butadiene.............................                                        20.9        -29.2          6.1
----------------------------------------------------------------------------------------------------------------
                                              Non-Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC.......................................  MOBILE6.2 & CRC E-65.........          -30          -30          -18
Benzene...................................  MOBILE6.2 & Complex Models...          -40          -43         -32
----------------------------------------------------------------------------------------------------------------
\a\ Average per vehicle effects for the 2012 fleet during summer conditions.


[[Page 23972]]

    As can be seen, all three types of RFG produce significantly lower 
emissions of VOC, CO and benzene than conventional gasoline. The impact 
of ethanol RFG on non-exhaust VOC emissions is lower than the other two 
types of RFG due to the impact of ethanol on permeation emissions. The 
impact of RFG on emissions of NOX and the other air toxics 
depends on the type of RFG blend. The most notable effect on toxic 
emissions in percentage terms is the 173 percent increase in 
acetaldehyde with the use of ethanol. However, as will be seen below, 
base acetaldehyde emissions are low relative to the other toxics. While 
not shown, the total mass emissions of the four toxic pollutants always 
decreases, as benzene is by far the largest constituent.
    It should be noted that these comparisons assume that all gasoline 
blends meet EPA's Tier 2 gasoline sulfur standard of 30 ppm. Prior to 
the Tier 2 program, RFG contained less sulfur than conventional 
gasoline and reduced NOX emissions to a greater degree 
compared to conventional gasoline.
    Historically, no non-oxygenated RFG was sold, due to the 
requirement that RFG contain at least 2.0 weight percent oxygen. 
However, with the Energy Act's removal of this requirement, all three 
types of RFG blends can be sold today. Increased use of ethanol in RFG 
would therefore either replace MTBE RFG or non-oxygenated RFG. The 
former has already occurred in many areas, as MTBE was essentially 
removed from the U.S. gasoline market by the end of 2006. The impact of 
using ethanol in RFG in lieu of MTBE or no oxygenate can be seen from 
comparing the relative impacts of the various RFG blends shown in Table 
VIII.A.1.b-1.
    Blending RFG with ethanol instead of MTBE or no oxygenate will 
increase VOC and NOX emissions and decrease CO emissions. 
Exhaust benzene and formaldehyde emissions will decrease, but non-
exhaust benzene, acetaldehyde, and 1,3-butadiene emissions will 
increase. All of these impacts are on a per vehicle basis and apply to 
Tier 0 vehicles only. The overall impact of increased ethanol use on 
total emissions of these various pollutants is described below.
    Table VIII.A.1.b-2 presents the effect of blending either MTBE or 
ethanol into conventional gasoline while matching octane.

Table VIII.A.1.B-2.--Effect of MTBE and Ethanol in Conventional Gasoline
    on Tier 0 Vehicle Emissions Relative to a Typical Non-Oxygenated
                         Conventional Gasoline a
------------------------------------------------------------------------
                                                 11 Volume    10 Volume
          Pollutant                 Source        percent      percent
                                                    MTBE     ethanol \b\
------------------------------------------------------------------------
Exhaust VOC..................  EPA Predictive          -9.2         -7.4
                                Models.
NOX..........................                          -2.6          7.7
CO \c\.......................  MOBILE6.2......       -6/-11      -11/-19
Exhaust Benzene..............  EPA Predictive         -22.8        -24.9
                                and Complex
                                Models.
Formaldehyde.................                         +21.3         +6.7
Acetaldehyde.................                          +0.8       +156.8
1,3-Butadiene................                          -3.7        -13.2
Non-Exhaust VOC..............  MOBILE6.2......         Zero          +30
Non-Exhaust Benzene..........  MOBILE6.2 &             -9.5        +15.8
                                Complex Models.
------------------------------------------------------------------------
a Average per vehicle effects for the 2012 fleet during summer
  conditions.
b Assumes a 1.0 psi RVP waiver for ethanol blends.
c The first figure shown applies to normal emitters; the second applies
  to high emitters.

    Use of either oxygenate reduces exhaust VOC and CO emissions, but 
increases NOX emissions. The ethanol blend increases non-
exhaust VOC emissions due to the commonly granted 1.0 psi waiver of the 
RVP standard, as well as increased permeation emissions. Both 
oxygenated blends reduce exhaust benzene and 1,3-butadiene emissions. 
As above, ethanol increases non-exhaust benzene and acetaldehyde 
emissions. While small amounts of MTBE may have still been used in CG 
in 2004, for our reference case we have assumed that all MTBE use was 
in RFG. Therefore, we are not predicting any emissions impact related 
to removing MTBE from conventional gasoline. Increased use of 
conventional ethanol blends will be in lieu of non-oxygenated 
conventional gasoline. Thus, the more relevant column in Table 
VII.A.1.b-2 for our modeling is the last column, which shows the 
emission impact of a 10 volume percent ethanol blend relative to non-
oxygenated gasoline.
    The exhaust emission effects shown above for VOC and NOX 
emissions only apply to Tier 0 vehicles in our primary analysis. For 
example, MOBILE6.2 estimates that 34 of exhaust VOC emissions and 16 of 
NOX emissions from gasoline vehicles in 2012 come from Tier 
0 vehicles. In the sensitivity analysis, these effects are extended to 
all gasoline vehicles. The effect of RVP and permeation on non-exhaust 
VOC emissions is temperature dependent. The figures shown above are 
based on the distribution of temperatures occurring across the U.S. in 
July.
    We received several comments related to the effect of ethanol on 
emissions from onroad vehicles. None of the comments led us to change 
the basic approach taken to estimating the impact of changing fuel 
quality described above. Several comments suggested that we expand our 
discussion of the uncertainty in these fuel effects (as well as the 
effects of fuel quality on emissions from nonroad equipment and diesels 
described below). While such an expanded discussion might be generally 
desirable, the lack of relevant emission data from late model vehicles 
and equipment prevents this. We believe that we have adequately 
described the uncertainty in the emission estimates presented below and 
our plans to obtain more data in order to improve these estimates in 
the near future.
c. Nonroad Equipment
    To estimate the effect of gasoline quality on emissions from 
nonroad equipment, we used EPA's NONROAD emission model. We used the 
2005 version of this model, NONROAD2005, which includes the effect of 
ethanol on permeation emissions from most nonroad equipment.
    Only sulfur and oxygen content affect exhaust VOC, CO and 
NOX emissions in NONROAD. Since sulfur level is assumed to 
remain constant, the only difference in exhaust emissions between 
conventional and reformulated gasoline is due to oxygen content. Table 
VIII.A.1.c-1 shows the effect of adding

[[Page 23973]]

11 volume percent MTBE or 10 volume percent ethanol to non-oxygenated 
gasoline on these emissions.

 Table VIII.A.1.C-1.--Effect MTBE and Ethanol on Nonroad Exhaust Emissions Relative to a Typical Non-Oxygenated
                                                    Gasoline
----------------------------------------------------------------------------------------------------------------
                                                                  4-Stroke engines          2-Stroke engines
                                                             ---------------------------------------------------
                          Base fuel                            11 Volume    10 Volume    11 Volume    10 Volume
                                                                percent      percent      percent      percent
                                                                  MTBE       ethanol        MTBE       ethanol
----------------------------------------------------------------------------------------------------------------
Exhaust VOC.................................................           -9          -16           -1           -2
Non-Exhaust VOC.............................................            0           26            0           26
CO..........................................................          -13          -22          -13          -23
NOX.........................................................          +23          +40          +37          +65
----------------------------------------------------------------------------------------------------------------

    As can be seen, higher oxygen content reduces exhaust VOC and CO 
emissions significantly, but also increases NOX emissions. 
However, NOX emissions from these engines tend to be fairly 
low to start with, given the fact that these engines run much richer 
than stoichiometric. Thus, a large percentage increase of a relative 
low base value can be a relatively small increase in absolute terms.
    Evaporative emissions from nonroad equipment are impacted by only 
RVP, and permeation by ethanol content. Both the RVP increase due to 
blending of ethanol and its permeation effect cause non-exhaust VOC 
emissions to increase with the use of ethanol in nonroad equipment. The 
26 percent effect represents the average impact across the U.S. in July 
for both 2-stroke and 4-stroke equipment. We updated the NONROAD2005 
hose permeation emission factors for small spark-ignition engines and 
recreational marine watercraft to reflect the use of ethanol.
    For nonroad toxics emissions, we base our estimates of the impact 
of fuel quality on the fraction of exhaust VOC emissions represented by 
each toxic on MOBILE6.2 (i.e., the same effects predicted for onroad 
vehicles). The National Mobile Inventory Model (NMIM) contains 
estimates of the fraction of VOC emissions represented by the various 
air toxics based on oxygenate type (none, MTBE or ethanol). However, 
estimates for nonroad gasoline engines running on different fuel types 
are limited, making it difficult to accurately model the impacts of 
changes in fuel quality. In the recent final rule addressing mobile air 
toxic emissions, EPA replaced the toxic-related fuel effects contained 
in NMIM with those from MOBILE6.2 for onroad vehicles.\106\ We follow 
the same methodology here. Future testing could significantly alter 
these emission impact estimates.
---------------------------------------------------------------------------

    \106\ 71, Federal Register, 15804, March 29, 2006.
---------------------------------------------------------------------------

2. Diesel Fuel Quality: Biodiesel
    EPA assessed the impact of biodiesel fuel on emissions in 2002 and 
published a draft report summarizing the results.\107\ This report 
included a technical analysis of biodiesel effects on regulated and 
unregulated pollutants from diesel powered vehicles and concluded that 
biodiesel fuels improved PM, HC and CO emissions of diesel engines 
while slightly increasing their NOX emissions.
---------------------------------------------------------------------------

    \107\ ``A Comprehensive Analysis of Biodiesel Impacts on Exhaust 
Emissions,'' Draft Technical Report, U.S. EPA, EPA420-P-02-001, 
October 2002. http://www.epa.gov/otaq/models/biodsl.htm.

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

    While the conclusions reached in the 2002 EPA report relative to 
biodiesel effects on VOC, CO and PM emissions have been generally 
accepted, the magnitude of the B20 effect on NOX remains 
controversial due to conflicting results from different studies. 
Significant new testing is being planned with broad stakeholder 
participation and support in order to better estimate the impact of 
biodiesel on NOX and other exhaust emissions from the in-use 
fleet of diesel engines. We hope to incorporate the data from such 
additional testing into the analyses for other studies required by the 
Energy Act in 2008 and 2009, and into a subsequent rule to set the RFS 
program standard for 2013 and later.
3. Renewable Fuel Production and Distribution
    Areas experiencing increased renewable production will experience 
the corresponding emission increases associated with their production. 
The primary impact of renewable fuel production and distribution 
regards ethanol, since it is expected to be the predominant renewable 
fuel used in the foreseeable future. We approximate the impact of 
increased ethanol and biodiesel production, including corn and soy 
farming, on emissions based on DOE's GREET model, version 1.7. In 
addition, we develop a second estimate of emissions from ethanol 
production facilities using estimates of emissions from current ethanol 
plants obtained from the States. We also include emissions effects 
resulting from the transport of increased volumes of renewable fuels 
and decreased volumes of gasoline and diesel fuel. These emissions are 
summarized in Table VIII.A.3-1.

            Table VIII.A.3-1.--Well-to-Pump Emissions for Producing and Distributing Renewable Fuels
                                   [Grams per gallon ethanol or biodiesel] \a\
----------------------------------------------------------------------------------------------------------------
                                                 GREET1.7            GREET1.7 + state data
                                        ----------------------------------------------------
               Pollutant                   Current       Future      Current       Future    Biodiesel--GREET1.7
                                           ethanol      ethanol      ethanol      ethanol
                                            plants       plants       plants       plants
----------------------------------------------------------------------------------------------------------------
VOC....................................          1.8          1.8          3.6          3.2             37.6
CO.....................................          4.0          4.1          4.4          4.3             12.7
NOX....................................         11.4         11.4         10.8         13.0             25.1
PM10...................................          4.9          4.9          6.1          2.8              4.8

[[Page 23974]]


SOX....................................          6.4          6.4          7.2          9.7             21.8
----------------------------------------------------------------------------------------------------------------
\a\ Includes credit for reduced distribution of gasoline and diesel fuel.

    At the same time, areas with refineries might experience reduced 
emissions, not necessarily relative to current emission levels, but 
relative to those which would have occurred in the future had renewable 
fuel use not risen. However, to the degree that increased renewable 
fuel use reduces imports of gasoline and diesel fuel, as opposed to the 
domestic production of these fuels, these reduced refinery emissions 
will occur overseas and not in the U.S.
    Similarly, areas with MTBE production facilities might experience 
reduced emissions from these plants as they cease producing MTBE. 
However, many of these plants may be converted to produce other 
gasoline blendstocks, such as iso-octane or alkylate. In this case, 
their emissions are not likely to change substantially.

B. Impact on Emission Inventories

    We use the NMIM to estimate emissions under the various ethanol 
scenarios on a county by county basis. NMIM basically runs MOBILE6.2 
and NONROAD2005 with county-specific inputs pertaining to fuel quality, 
ambient conditions, levels of onroad vehicle VMT and nonroad equipment 
usage, etc. We ran NMIM for two months, July and January. We estimate 
annual emission inventories by summing the two monthly inventories and 
multiplying by six.
    As described above, we removed the effect of gasoline fuel quality 
on exhaust VOC and NOX emissions from the onroad motor 
vehicle inventories which are embedded in MOBILE6.2. We then applied 
the exhaust emission effects from the EPA Predictive Models. In our 
primary analysis, we only applied these EPA Predictive Model effects to 
exhaust VOC and NOX emissions from Tier 0 vehicles. In a 
sensitivity case, we applied them to exhaust VOC and NOX 
emissions from all vehicles. Regarding the effect of fuel quality on 
emissions of four air toxics from nonroad equipment (in terms of their 
fraction of VOC emissions), in all cases we replaced the fuel effects 
contained in NMIM with those for motor vehicles contained in MOBILE6.2. 
The projected emission inventories for the primary analysis are 
presented first, followed by those for the sensitivity analysis.
1. Primary Analysis
    The national emission inventories for VOC, CO and NOX in 
2012 with current fuels (i.e., ``reference fuel'') are summarized in 
Table VIII.B.1-1. Also shown are the changes in emissions projected for 
the two levels of ethanol use (i.e., ``control cases'') described in 
Section VI.

 Table VIII.B.1-1.--2012 Emissions Nationwide From Gasoline Vehicles and
     Equipment Under Several Ethanol Use Scenarios--Primary Analysis
                          [Tons per year] \108\
------------------------------------------------------------------------
                                    Inventory    Change in inventory in
                                  -------------       control cases
            Pollutant               Reference  -------------------------
                                       case       RFS case     EIA case
------------------------------------------------------------------------
VOC..............................    5,882,000       18,000       43,000
NOX..............................    2,487,000       23,000       40,000
CO...............................   55,022,000     -483,000   -1,366,000
Benzene..........................      178,000       -3,200       -7,200
Formaldehyde.....................       40,400         -600         -200
Acetaldehyde.....................       19,900        3,400        7,100
1,3-Butadiene....................       18,900         -200         -300
------------------------------------------------------------------------

    Both VOC and NOX emissions are projected to increase 
with increased use of ethanol. However, the increases are small, 
generally less than 2 percent. CO emissions are projected to decrease 
by about 0.9 to 2.5 percent. Benzene emissions are projected to 
decrease by 1.8 to 4.0 percent. Formaldehyde emissions are projected to 
decrease slightly, on the order of 0.5 to 1.5 percent. 1,3-butadiene 
emissions are projected to decrease by about 1.1 to 1.6 percent. The 
largest change is in acetaldehyde emissions, an increase of 17.1 to 
35.7 percent, as acetaldehyde is a partial combustion product of 
ethanol.
---------------------------------------------------------------------------

    \108\ These emission estimates do not include the impact of the 
recent mobile source air toxic standards (72 FR 8428, February 26, 
2007).
---------------------------------------------------------------------------

    CO also participates in forming ozone, much like VOCs. Generally, 
CO is 15-50 times less reactive than typical VOC. Still, the reduction 
in CO emissions is roughly 27-32 times the increase in VOC emissions in 
the two scenarios. Thus, the projected reduction in CO emissions is 
important from an ozone perspective. However, as described above, the 
methodology for projecting the effect of ethanol use on CO emissions is 
inconsistent with that for exhaust VOC and NOX emissions. 
Thus, comparisons between changes in VOC and CO emissions are 
particularly uncertain.
    There will also be some increases in emissions due to ethanol and 
biodiesel production. Table VIII.B.1-2 shows estimates of annual 
emissions expected to occur nationwide due to increased production of 
ethanol. These estimates include a reduction in emissions related to 
the distribution of the displaced gasoline. The table reflects the use 
of

[[Page 23975]]

emissions factors from DOE's GREET model, version 1.7, as well as 
estimates of ethanol plant emissions obtained from the States. It 
should be noted that emissions in the base case assume an 80/20 mix of 
dry mill and wet mill facilities. New plants (and thus, the emission 
increases) assume 100% dry mill facilities.

         Table VIII.B.1-2.--Annual Emissions Nationwide From Ethanol Production and Transportation: 2012
                                                 [Tons per year]
----------------------------------------------------------------------------------------------------------------
                                                   GREET1.7                        GREET1.7 + State data
                                   -----------------------------------------------------------------------------
                                     Base case     RFS case     EIA case    Base case     RFS case     EIA case
----------------------------------------------------------------------------------------------------------------
                                      Emissions    Increase in emissions     Emissions    Increase in emissions
----------------------------------------------------------------------------------------------------------------
VOC...............................        8,000        5,000       11,000       14,000       10,000       20,000
NOX...............................       17,000       13,000       26,000       18,000       14,000       27,000
CO................................       49,000       35,000       72,000       56,000       40,000       81,000
PM10..............................       21,000       15,000       30,000       12,000        9,000       18,000
SOX...............................       27,000       20,000       41,000       42,000       30,000       61,000
----------------------------------------------------------------------------------------------------------------

    As can be seen, the potential increases in emissions from ethanol 
production and transportation are of the same order of magnitude as 
those from ethanol use, with the exception of CO emissions. The vast 
majority of these emissions are related to farming and ethanol 
production. Both farms and ethanol plants are generally located in 
ozone attainment areas.
    Where counties are constructing new ethanol plants, expanding 
existing plants, or planning construction for future plants, the 
average increase in VOC and NOX emissions from plants alone 
are about 26 tons/month VOC and 35 tons/month NOX using 
state data (about 17 tons/month VOC and 25 tons/month NOX 
using GREET 1.7 emission factors). Average VOC and NOX 
emissions increase to about 61 tons/month and 83 tons/month, 
respectively, in the 10% of counties expecting largest increases in 
ethanol production. For both VOC and NOX, emissions 
estimates are about 35% less when using the GREET 1.7 emission factors.
    Table VIII.B.1-3 shows estimates of annual emissions expected to 
occur nationwide due to increased production of biodiesel. These 
estimates include a reduction in emissions related to the distribution 
of the displaced diesel fuel. Again, these emissions are generally 
expected to be in ozone attainment areas.

Table VIII.B.1-3.--Annual Emissions Nationwide From Biodiesel Production
                           and Transportation
                             [Tons per year]
------------------------------------------------------------------------
                                                                 2012
                                                 Reference    Emissions
                                                 inventory:   inventory:
                   Pollutant                    30 mill gal    300 mill
                                                 biodiesel       gal
                                                  per year    biodiesel
                                                               per year
------------------------------------------------------------------------
VOC...........................................        1,400       14,000
NOX...........................................        1,500       15,000
CO............................................          800        8,000
PM10..........................................           50          500
SOX...........................................          250        2,500
------------------------------------------------------------------------

2. Sensitivity Analysis
    The national emission inventories for VOC and NOX in 
2012 with current fuels are summarized in Table VIII.B.2-1. Here, the 
emission effects contained in the EPA Predictive Models are assumed to 
apply to all vehicles, not just Tier 0 vehicles. Also shown are the 
changes in emissions projected for the two cases for future ethanol 
volume.

 Table VIII.B.2-1.--2012 Emissions Nationwide From Gasoline Vehicles and
 Equipment Under Two Future Ethanol Use Scenarios--Sensitivity Analysis
                             [Tons per year]
------------------------------------------------------------------------
                                    Inventory    Change in inventory in
                                  -------------       control cases
            Pollutant               Reference  -------------------------
                                       case       RFS case     EIA case
------------------------------------------------------------------------
VOC..............................    5,834,000      -20,000       -4,000
NOX..............................    2,519,000       68,000      106,000
CO...............................   54,315,000     -692,000   -1,975,000
Benzene..........................      175,700       -5,000       -9,400
Formaldehyde.....................       39,600       -1,100         -700
Acetaldehyde.....................       19,500        3,000        6,600
1,3-Butadiene....................       18,600         -400         -600
------------------------------------------------------------------------

    The overall VOC and NOX emission impacts of the various 
ethanol use scenarios change to some degree when all motor vehicles are 
assumed to be sensitive to fuel ethanol content. The increase in VOC 
emissions turns into a net decrease due to a greater reduction in 
exhaust VOC emissions from onroad vehicles. However, the increase in 
NOX emissions gets larger, as more vehicles are assumed to 
be affected by ethanol. Emissions of the four air toxics generally 
decrease slightly, due to the greater reduction in exhaust VOC 
emissions.

[[Page 23976]]

3. Local and Regional VOC and NOX Emission Impacts in July
    We also estimate the percentage change in VOC, NOX, and 
CO emissions from gasoline fueled motor vehicles and equipment in those 
areas which actually experienced a significant change in ethanol use. 
Specifically, we focused on areas where the market share of ethanol 
blends was projected to change by 50 percent or more. We also focused 
on summertime emissions, as these are most relevant to ozone formation. 
Finally, we developed separately estimates for: (1) RFG areas, 
including the state of California and the portions of Arizona where 
their CBG fuel programs apply, (2) low RVP areas (i.e., RVP standards 
less than 9.0 RVP, and (3) areas with a 9.0 RVP standard. This set of 
groupings helps to highlight the emissions impact of increased ethanol 
use in those areas where emission control is most important.
    Table VIII.B.3-1 presents our primary estimates of the percentage 
change in VOC, NOX, and CO emission inventories for these 
three types of areas. Note that the analyses here are very similar to 
those described in Section 5.1 of the RIA, with the exception that 
Table VIII.B.3-1 below reflects 50 states (instead of 37 eastern 
states) and excludes diesel emissions.

 Table VIII.B.3-1.--July 2015 Change in Emissions from Gasoline Vehicles
   and Equipment in Counties Where Ethanol Use Changed Significantly--
                            Primary Analysis
------------------------------------------------------------------------
           Ethanol use                 RFS case            EIA case
------------------------------------------------------------------------
                                RFG Areas
------------------------------------------------------------------------
Ethanol Use.....................  Down..............  Up.
VOC.............................  0.8%..............  2.3%.
NOX.............................  -3.4%.............  1.6%.
CO..............................  6.1%..............  -2.6%.
------------------------------------------------------------------------
                              Low RVP Areas
------------------------------------------------------------------------
Ethanol Use.....................  Up................  Up.
VOC.............................  4.2%..............  4.6%.
NOX.............................  6.2%..............  5.7%.
CO..............................  -12.5%............  -13.7%.
------------------------------------------------------------------------
                          Other Areas (9.0 RVP)
------------------------------------------------------------------------
Ethanol Use.....................  Up................  Up.
VOC.............................  3.6%..............  4.6%.
NOX.............................  7.3%..............  7.0%.
CO..............................  -6.4%.............  -6.0%.
------------------------------------------------------------------------

    As expected, increased ethanol use tends to increase NOX 
emissions. The increase in low RVP and other areas is greater than in 
RFG areas, since the RFG in the RFG areas included in this analysis all 
contained MTBE. Also, increased ethanol use tends to increase VOC 
emissions, indicating that the increase in non-exhaust VOC emissions 
exceeds the reduction in exhaust VOC emissions. This effect is muted 
with RFG due to the absence of an RVP waiver for ethanol blends. We 
would expect very similar results for 2012. The reader is referred to 
Chapter 2 of the RIA for discussion of how ethanol levels will change 
at the state-level.
    Table VIII.B.3-2 presents the percentage change in VOC, 
NOX, and CO emission inventories under our sensitivity case 
(i.e., when we apply the emission effects of the EPA Predictive Models 
to all motor vehicles).

 Table VIII.B.3-2.--July 2015 Change in Emissions From Gasoline Vehicles
   and Equipment in Counties Where Ethanol Use Changed Significantly--
                          Sensitivity Analysis
------------------------------------------------------------------------
           Ethanol use                 RFS case            EIA case
------------------------------------------------------------------------
                                RFG Areas
------------------------------------------------------------------------
Ethanol Use.....................  Down..............  Up.
VOC.............................  -1.0%.............  1.0%.
NOX.............................  -0.9%.............  5.6%.
CO..............................  7.3%..............  -3.0%.
------------------------------------------------------------------------
                              Low RVP Areas
------------------------------------------------------------------------
Ethanol Use.....................  Up................  Up.
VOC.............................  3.4%..............  3.7%.
NOX.............................  10.4%.............  10.8%.
CO..............................  -15.0%............  -16.4%.
------------------------------------------------------------------------
                          Other Areas (9.0 RVP)
------------------------------------------------------------------------
Ethanol Use.....................  Up................  Up.
VOC.............................  3.0%..............  3.9%.
NOX.............................  10.8%.............  11.0%.

[[Page 23977]]


CO..............................  -9.0%.............  -8.9%.
------------------------------------------------------------------------

    Directionally, the changes in VOC and NOX emissions in 
the various areas are consistent with those from our primary analysis. 
The main difference is that the increases in VOC emissions are smaller, 
due to more vehicles experiencing a reduction in exhaust VOC emissions, 
and the increases in NOX emissions are larger.

C. Impact on Air Quality

    We estimate the impact of increased ethanol use on the ambient 
concentrations of two pollutants: Ozone and PM. Quantitative estimates 
are made for ozone, while only qualitative estimates can be made 
currently for ambient PM. These impacts are described below.
1. Impact of Increased Ethanol Use on Ozone
    We use a metamodeling tool developed at EPA, the ozone response 
surface metamodel (Ozone RSM), to estimate the effects of the projected 
changes in emissions from gasoline vehicles and equipment for the RFS 
and EIA cases. We included the estimated changes in emissions from 
renewable fuel production and distribution. Because of limitations in 
the Ozone RSM, we could not easily assign these emissions to the 
specific counties where the plants are or are expected to be located. 
Instead, we assigned all of the emissions related to renewable fuel 
production and distribution to the set of states expected to contain 
most of the production facilities.
    The Ozone RSM was created using multiple runs of the Comprehensive 
Air Quality Model with Extensions (CAMX). Base and proposed 
control CAMX metamodeling was completed for the year 2015 
over a modeling domain that includes all or part of 37 Eastern U.S. 
states, plus the District of Columbia. For more information on the 
Ozone RSM, please see Chapter 5 of the RIA for this final rule.
    The Ozone RSM limits the number of geographically distinct changes 
in VOC and NOX emissions which can be simulated. As a 
result, we could not apply distinct changes in emissions for each 
county. Therefore, two separate runs were made with different VOC and 
NOX emissions reductions. We then selected the ozone impacts 
from the various runs which best matched the VOC and NOX 
emission reductions for that county. This models the impact of local 
emissions reasonably well, but loses some accuracy with respect to 
ozone transport. No ozone impact was assumed for areas which did not 
experience a significant change in ethanol use. The predicted ozone 
impacts of increased ethanol use for those areas where ethanol use is 
projected to change by more than a 50% market share are summarized in 
Table VIII.C.1-1. As shown in the Table 5.1-2 of the RIA, national 
average impacts (based on the 37-state area modeled) which include 
those areas where no change in ethanol use is occurring are 
considerably smaller.

                Table VIII.C.1-1.--Impact on 8-Hour Design Value Equivalent Ozone Levels (ppb) a
----------------------------------------------------------------------------------------------------------------
                                                                  Primary analysis        Sensitivity analysis
                                                             ---------------------------------------------------
                                                                RFS case     EIA case     RFS case     EIA case
----------------------------------------------------------------------------------------------------------------
Minimum Change..............................................       -0.015        0.000       -0.115        0.028
Maximum Change..............................................        0.329        0.337        0.624        0.549
Average Change \b\..........................................        0.153        0.181        0.300        0.325
Population-Weighted Change \b\..............................        0.154        0.183        0.272       0.315
----------------------------------------------------------------------------------------------------------------
\a\ In comparison to the 80 ppb 8-hour ozone standards.
\b\ Only for those areas experiencing a change in ethanol blend market share of at least 50 percent.

    As can be seen, ozone levels generally increase to a small degree 
with increased ethanol use. This is likely due to the projected 
increases in both VOC and NOX emissions. Some areas do see a 
small decrease in ozone levels. In our primary analysis, where exhaust 
emissions from Tier 1 and later onroad vehicles are assumed to be 
unaffected by ethanol use, the population-weighted increase in ambient 
ozone levels in those areas where ethanol use changed significantly is 
0.154-0.183 ppb. Since the 8-hour ambient ozone standard is 85 ppb, 
this increase represents about 0.2 percent of the standard, a very 
small percentage.
    In our sensitivity analysis, where exhaust emissions from Tier 1 
and later onroad vehicles are assumed to respond to ethanol like Tier 0 
vehicles, the population-weighted increase in ambient ozone levels is 
slightly less than twice as high, or 0.272-0.315 ppb. This increase 
represents about 0.35 percent of the standard.
    There are a number of important caveats concerning these estimates. 
First, the emission effects of adding ethanol to gasoline are based on 
extremely limited data for recent vehicles and equipment. Second, the 
Ozone RSM does not account for changes in CO emissions. As shown above, 
ethanol use should reduce CO emissions significantly, directionally 
reducing ambient ozone levels in those areas where ozone formation is 
VOC-limited. (Ozone levels in areas which are NOX-limited 
are less likely to be affected by a change in CO emissions.) The Ozone 
RSM also does not account for changes in VOC reactivity. With 
additional ethanol use, the ethanol content of VOC should increase. 
Ethanol is less reactive than the average VOC. Therefore, this change 
should also reduce ambient ozone levels in a way not addressed by the 
Ozone RSM, again in those areas where ozone formation is predominantly 
VOC-limited. Because of these limitations, anyone interested in the 
impact of increased ethanol use on ozone in any particular area should 
utilize more comprehensive dispersion modeling which accounts for these 
and other important factors.
    We received several requests in comments on the proposal to 
quantify the impact of the reduced CO emissions

[[Page 23978]]

and VOC reactivity on ozone. As discussed in the S&A document, this is 
not possible without running more sophisticated ambient dispersion 
models. The impact of CO emissions and VOC reactivity on ozone vary 
significantly depending on ambient conditions and the relative amount 
of VOC and NOX in the atmosphere. Therefore, general rules 
of thumb cannot be applied.
    Moving to health effects, exposure to ozone has been linked to lung 
function decrements, respiratory symptoms, aggravation of asthma, 
increased hospital and emergency room visits, increased asthma 
medication usage, inflammation of the lungs, and a variety of other 
respiratory effects and cardiovascular effects including premature 
mortality. Ozone can also adversely affect the agricultural and 
forestry sectors by decreasing yields of crops and forests. Although 
the health and welfare impacts of changes in ambient ozone levels are 
typically quantified in regulatory impact analyses, we do not evaluate 
them for this analysis. On average, the changes in ambient ozone levels 
shown above are small and would be even smaller if changes in CO 
emissions and VOC reactivity were taken into account. The increase in 
ozone would likely lead to negligible monetized impacts. We therefore 
do not estimate and monetize ozone health impacts for the changes in 
renewable use due to the small magnitude of this change, and the 
uncertainty present in the air quality modeling conducted here, as well 
as the uncertainty in the underlying emission effects themselves 
discussed earlier.
2. Particulate Matter
    Ambient PM can come from two distinct sources. First, PM can be 
directly emitted into the atmosphere. Second, PM can be formed in the 
atmosphere from gaseous pollutants. Gasoline-fueled vehicles and 
equipment contribute to ambient PM concentrations in both ways.
    As described above, we are not currently able to predict the impact 
of fuel quality on direct PM emissions from gasoline-fueled vehicles or 
equipment. Therefore, we are unable at this time to project the effect 
that increased ethanol use will have on levels of directly emitted PM 
in the atmosphere.
    PM can also be formed in the atmosphere (termed secondary PM here) 
from several gaseous pollutants emitted by gasoline-fueled vehicles and 
equipment. Sulfur dioxide emissions contribute to ambient sulfate PM. 
NOX emissions contribute to ambient nitrate PM. VOC 
emissions contribute to ambient organic PM. Increased ethanol use is 
not expected to change gasoline sulfur levels, so emissions of sulfur 
dioxide and any resultant ambient concentrations of sulfate PM are not 
expected to change. Increased ethanol use is expected to increase 
NOX emissions, so the possibility exists that ambient 
nitrate PM levels could increase. Increased ethanol is generally 
expected to increase total VOC emissions, which could also impact the 
formation of secondary organic PM. However, while non-exhaust VOC 
emissions are expected to increase, exhaust VOC emissions are expected 
to decrease. Generally, the higher the molecular weight of the specific 
VOC emitted, the greater the likelihood it will form PM in the 
atmosphere. Non-exhaust VOC is predominantly low in molecular weight, 
as much of it is due to fuel evaporating. Thus, emissions of VOCs 
likely to form PM in the atmosphere are likely decreasing with ethanol 
use.
    The formation of secondary organic PM is very complex, due in part 
to the wide variety of VOCs emitted into the atmosphere. The degree to 
which a specific gaseous VOC reacts to form PM in the atmosphere 
depends on the types of reactions that specific VOC undergoes and the 
products of those reactions. Both of these factors depend on other 
pollutants present, such as the hydroxyl radical, ozone, NOX 
and other reactive compounds. The relative mass of secondary PM formed 
per mass of gaseous VOC emitted can also depend on the total 
concentration of gaseous VOC and organic PM in the atmosphere. Most of 
the secondary organic PM exists in a continually changing equilibrium 
between the gaseous and PM phases. Both the rates of these reactions 
and the gaseous-PM equilibria depend on temperature, so seasonal 
differences can be expected.
    Recent smog chamber studies have indicated that gaseous aromatic 
VOCs can form secondary PM under certain conditions. These compounds 
comprise a greater fraction of exhaust VOC emissions than non-exhaust 
VOC emissions, as non-exhaust VOC emissions are dominated by VOCs with 
relatively high vapor pressures. Aromatic VOCs tend to have lower vapor 
pressures. As increased ethanol use is expected to reduce exhaust VOC 
emissions, emissions of aromatic VOCs should also decrease. In 
addition, refiners are expected to reduce the aromatic content of 
gasoline by 5 volume percentage points as ethanol is blended into 
gasoline. Emissions of aromatic VOCs should decrease with lower 
concentrations of aromatics in gasoline. Thus, emissions of gaseous 
aromatic VOCs could decrease for both reasons.
    Overall, we expect that the decrease in secondary organic PM is 
likely to exceed the increase in secondary nitrate PM. In 1999, 
NOX emissions from gasoline-fueled vehicles and equipment 
comprised about 20% of national NOX emissions from all 
sources. In contrast, gasoline-fueled vehicles and equipment comprised 
over 60% of all national gaseous aromatic VOC emissions. The percentage 
increase in national NOX emissions due to increased ethanol 
use should be smaller than the percentage decrease in national 
emissions of gaseous aromatics. Finally, in most urban areas, ambient 
levels of secondary organic PM exceed those of secondary nitrate PM. 
Thus, directionally, we expect a net reduction in ambient PM levels due 
to increased ethanol use. However, we are unable to quantify this 
reduction at this time.
    EPA currently utilizes the CMAQ model to predict ambient levels of 
PM as a function of gaseous and PM emissions. This model includes 
mechanisms to predict the formation of nitrate PM from NOX 
emissions. However, it does not currently include any mechanisms 
addressing the formation of secondary organic PM. EPA is currently 
developing a model of secondary organic PM from gaseous toluene 
emissions. We plan to incorporate this mechanism into the CMAQ model in 
2007. The impact of other aromatic compounds will be added as further 
research clarifies their role in secondary organic PM formation. 
Therefore, we expect to be able to quantitatively estimate the impact 
of decreased toluene emissions and increased NOX emissions 
due to increased ethanol use as part of future analyses of U.S. fuel 
requirements required by the Act.

IX. Impacts on Fossil Fuel Consumption and Related Implications

    Renewable fuels have been of significant interest for many years 
due to their potential to displace fossil fuels, which have often been 
targeted as primary contributors to emissions of greenhouse gases such 
as carbon dioxide, and national energy concerns primarily due to an 
increasing dependence on foreign sources of petroleum. In the Notice of 
Proposed Rulemaking, we provided a preliminary assessment of the 
greenhouse gas emission and energy impacts of renewable fuel and an 
initial assessment of the economic value of renewable fuel displacing 
petroleum-based fuels. We

[[Page 23979]]

also indicated that we would be updating an analysis of energy security 
impacts that had been prepared by analysts at the Oak Ridge National 
Laboratory (ORNL) of the Department of Energy. We present some 
discussion of that analysis here.
    We also performed a full lifecycle or well-to-wheel analysis for 
this final rule to estimate the GHG and fossil energy reductions from 
replacing petroleum based fuels with renewable fuels. Argonne National 
Laboratory's (ANL) GREET \109\ model was utilized for this lifecycle 
analysis. Table IX-1 summarizes this model's estimated impact that 
increases in the use of renewable fuels are projected to have on GHG 
emissions and fossil fuel consumption for the two renewable fuel volume 
scenarios considered in this final rulemaking relative to the reference 
case. As described later in this section, the results in Table IX-1 are 
based on a number of input assumptions including coal being used as 
process fuel in 14% of ethanol facilities.
---------------------------------------------------------------------------

    \109\ Greenhouse gases, Regulated Emissions, and Energy use in 
Transportation.
---------------------------------------------------------------------------

    As noted in Section III, although we have chosen to base our 
lifecycle analyses on Argonne National Laboratory's GREET model there 
are a variety of other lifecycle models and analyses available. The 
choice of model inputs and assumptions all have a bearing on the 
results of lifecycle analyses, and many of these assumptions remain the 
subject of debate among researchers. Lifecycle analyses must also 
contend with the fact that the inputs and assumptions generally 
represent industry-wide averages even though energy consumed and 
emissions generated can vary widely from one facility or process to 
another.
    There currently exists no organized, comprehensive dialogue among 
stakeholders about the appropriate tools and assumptions behind any 
lifecycle analyses. We will be initiating more comprehensive 
discussions about lifecycle analyses with stakeholders in the near 
future.

 Table IX-1.--GREET Model Lifecycle Reductions From Increased Renewable Fuel Use Relative to the 2012 Reference
                                                      Case
----------------------------------------------------------------------------------------------------------------
                                                                     RFS case                   EIA case
                                                           -----------------------------------------------------
                                                                          % of trans.                % of trans.
                                                              Reduction      sector      Reduction      sector
----------------------------------------------------------------------------------------------------------------
Fossil Energy (QBtu)......................................         0.15          0.48         0.27          0.85
Petroleum Energy (Bgal)...................................         2.0           0.82         3.9           1.60
GHG Emissions (MMT CO2-eq.)...............................         8.0           0.36        13.1           0.59
CO2 Emissions (MMT CO2)...................................        11.0           0.52        19.5           0.93
----------------------------------------------------------------------------------------------------------------

    We used the petroleum energy reductions shown in Table IX-1 to 
determine implications on imports of petroleum products. Our analysis 
found that calculated petroleum energy reductions come almost entirely 
from imports of finished products in this 2012 case and amount to the 
equivalent of 123,000 barrels of transportation fuel under the RFS case 
and 240,000 barrels of transportation fuel for the EIA case.
    Another effect of increased use of renewable fuels in the U.S. is 
that it diversifies the energy sources in making transportation fuel. 
Diverse sources of fuel energy reduce both financial and strategic 
risks associated with a potential disruption in supply or a spike in 
cost of a particular energy source. This reduction in risks is a 
measure of improved energy security. The ORNL report used an ``oil 
premium'' approach to identify those energy-security related impacts 
which are not reflected in the market price of oil, and which are 
expected to change in response to an incremental change in the level of 
U.S. oil imports.
    The following sections provide a more complete description of our 
analyses of the GHG emissions, fossil fuel, oil imports, and energy 
security impacts of this final rule.

A. Impacts on Lifecycle GHG Emissions and Fossil Energy Use

    Although the use of renewable fuels in the transportation sector 
directly displaces some petroleum consumed as motor vehicle fuel, this 
displacement of petroleum is in fact only one aspect of the overall 
impact of renewable fuels on fossil fuel use. Fossil fuels are also 
used in producing and transporting renewable feedstocks such as plants 
or animal byproducts, in converting the renewable feedstocks into 
renewable fuel, and in transporting and blending the renewable fuels 
for consumption as motor vehicle fuel. To estimate the true impacts of 
increases in renewable fuels on fossil fuel use, modelers attempt to 
take many or all these steps into account.
    Similarly, energy is used and GHGs emitted in the pumping of oil, 
transporting the oil to the refinery, refining the crude oil into 
finished transportation fuel, transporting the refined gasoline or 
diesel fuel to the consumer and then burning the fuel in the vehicle. 
Such analyses are termed lifecycle or well-to-wheels analyses. We 
performed a full lifecycle analysis as part of this final rulemaking to 
determine the GHG and fossil energy reductions from the increased use 
of renewable fuels.
    This lifecycle assessment approach and rationale were highlighted 
in the proposal. Comments received focused mainly on improving the 
process, for example the choice of lifecycle model used and initiating 
a stakeholder dialogue to build consensus around the assumptions and 
approach. In general comments were supportive of using a full lifecycle 
assessment approach, but differed on the appropriate model and 
associated assumptions EPA should use in its analysis.
1. Time Frame and Volumes Considered
    The results presented in this analysis represent a snapshot in 
time. They represent annual GHG and fossil fuel savings in the year 
considered, in this case 2012. Consistent with the emissions modeling 
described in Section VII, our analysis of the GHG and fossil fuel 
consumption impacts of renewable fuel use was conducted using three 
volume scenarios. The first scenario was the same reference case used 
elsewhere in this final rulemaking. The reference case scenario 
provided the point of comparison for the other two scenarios. The other 
two renewable fuel scenarios for 2012 represented the

[[Page 23980]]

RFS program requirements and the volume projected by EIA.
    In both the RFS and EIA scenarios, we assumed that the biodiesel 
production volume would be 0.303 billion gallons based on EIA AEO2006 
projections. Furthermore, for both scenarios we assume that 250 million 
gallons of ethanol that qualify for cellulosic biomass ethanol credit 
will be produced in 2012 from corn using biomass as the process energy 
source. The remaining renewable fuel volumes in each scenario would be 
ethanol made from corn and imports. The import volume is based on EIA's 
projections for the percent of total ethanol volume supplied by imports 
in 2012. The total volumes for all three scenarios are shown in Table 
II.A.1-1.
    For the purposes of calculating this difference or the amount of 
conventional fuel no longer consumed--that is, displaced--as a result 
of the use of the replacement renewable fuel, we assumed the ethanol 
volumes shown in Table II.A.1-1 are 5% denatured. The ethanol volumes 
were adjusted down to represent pure (100%) ethanol, biodiesel volumes 
were not adjusted. The adjusted volumes were then converted to total 
Btu using the appropriate volumetric energy content values (76,000 Btu/
gal for ethanol, 115,000 Btu/gal for gasoline, 118,000 Btu/gal for 
biodiesel, and 130,000 Btu/gal for diesel fuel). We make the assumption 
that vehicle energy efficiency will not be affected by the presence of 
renewable fuels (i.e., efficiency of combusting one Btu of ethanol is 
equal to the efficiency of combusting one Btu of gasoline).
    This lifecycle analysis is conducted without any regard to the 
geographic attributes of where emissions or energy use occurs; the 
model represents global reductions in GHG emissions and energy use, not 
just those occurring in the U.S. For example, under a full lifecycle 
assessment approach, the savings associated with reducing overseas 
crude oil extraction and refining are included, as are the 
international emissions associated with producing imported ethanol. 
There were two exceptions to this, both dealing with secondary impacts 
that may result internationally due to the expanded use of renewable 
fuels within the United States.
    The first exception is the emissions associated with international 
land use change. Due to decreasing corn exports some changes to 
international land use may occur, for example, as more crops are 
planted in other regions to compensate for the decrease in crop exports 
from the U.S. While the emissions associated with domestic land use 
change are well understood and are included in our lifecycle analysis, 
we did not include the potential impact on international land use and 
any emissions that might directly result. Our currently modeling 
capability does not allow us to assess what international land use 
changes would occur or how these changes would affect greenhouse gas 
emissions. For example, we would need to know how international 
cropping patterns would change as well as farming inputs and practices 
that might affect emissions assessment.
    The second case where we have not quantified the international 
impacts results from any reduction in world oil prices would tend to 
result from decreased demand in the U.S. as renewable fuels replace 
oil. It is commonly presumed in economic analyses that all else being 
equal quantity demanded of a valuable good (i.e., oil) will increase as 
price decreases. A world wide reduction of oil price would tend to 
reduce the cost of producing transportation fuel which in turn would 
tend to reduce the price consumers internationally would have to pay 
for this fuel.
    To the extent fuel prices are decreased, demand and consumption 
would tend to increase; this impact of reduced cost of driving is 
sometimes referred to as a ``rebound effect.'' Such a greater 
consumption internationally would presumably result in an increase in 
greenhouse gas emissions as consumers in the rest of the world drive 
more. These increased emissions would in part offset the emission 
impacts otherwise described in this preamble. While such international 
impacts of U.S. actions are important to understand, we have not have 
fully considered and quantified the international rebound effects of 
this renewable fuel standard. Nevertheless, such impacts remain an 
important consideration for future analysis.
2. GREET Model
    As in the analyses for the proposal, for this final rulemaking we 
used the GREET fuel-cycle model. GREET has been under development for 
several years and has undergone extensive peer review through multiple 
updates. Of the available sources of information on lifecycle analyses 
of energy consumed and emissions generated, we believe that GREET 
offers the most comprehensive treatment of the transportation sector. 
For this final rule, we used an updated version of the GREET model 
\110\, with a few modifications to its input assumptions. These changes 
since the NPRM are described below.
---------------------------------------------------------------------------

    \110\ GREET version 1.7, released November 10, 2006.
---------------------------------------------------------------------------

    The two main comments we received on our lifecycle modeling were 
that we should initiate a public dialogue on lifecycle analyses, models 
and assumptions, and that our sole reliance on the GREET model should 
be avoided, given other models are available. We have begun a public 
dialogue in that we identify the assumptions in the GREET model that 
were examined and modified for this final rulemaking. Furthermore, we 
will be initiating more comprehensive discussions about lifecycle 
analysis with stakeholders which could lead to an increased use of 
lifecycle analysis in future actions.
    In terms of our sole reliance on the GREET model, several other 
models have been developed for conducting renewable fuels lifecycle 
analysis. For example, researchers at the Energy and Resources Group 
(ERG) of the University of California Berkeley have developed the ERG 
Biofuel Analysis Meta-Model (EBAMM) and Mark Delucchi at the Institute 
of Transportation Studies of the University of California Davis has 
developed the Lifecycle Emissions Model (LEM). Other non-fuel specific 
lifecycle modeling tools could also be used to perform renewable fuel 
lifecycle analysis.
    Several studies have been released recently making use of these 
other models and showing different results than we find in the analysis 
done for this rule. For example, whereas GREET estimates a net GHG 
reduction of about 22% for corn ethanol compared to gasoline, the 
previously cited works by Farrell et al. utilizing the EBAMM show 
around a 13% reduction. The main difference in results is not due to 
the model used but assumptions on scope and input data.
    For example, most studies focus on average or current ethanol 
production which uses a current mix of wet and dry mill ethanol 
production and use of coal and natural gas as process energy. In 
contrast, for this rulemaking we consider future increases in renewable 
fuel production so we focus on new production capacity which will rely 
more heavily on more efficient dry mill production than the current mix 
of wet and dry mill capacities. Other studies also typically base 
ethanol and farm energy use on historic data while we are assuming 
future capacity increases will use a state of the art dry milling plant 
and most current farming energy use

[[Page 23981]]

data. Varying assumptions concerning how land use change impact 
CO2 emissions and agriculture related GHG emissions could 
also have an impact on overall results. Other studies also differ in 
the environmental flows considered. For example, GREET uses the 
internationally accepted set of greenhouse gases while Delucchi uses 
additional types of greenhouse gases.
    We have not had an opportunity to develop comparable analyses of 
the GHG and energy impacts of this rule using these other models. 
However, as discussed in chapters 6.1.1 and 6.2.3 of the RIA, we 
believe the scope of the GREET model and the assumptions we have used 
in running the model tend toward the middle of the range. Therefore we 
believe these results provide a reasonable assessment of the energy and 
GHG impacts of the expanded use of renewable fuels.
a. Renewable Fuel Pathways Considered
    The feedstocks and processes used to model renewable fuel 
production were those which our analysis in Chapter 1 of the RIA shows 
will primarily be used through 2012. However, other pathways for 
producing renewable fuels may become popular such as producing 
cellulosic biomass ethanol from municipal solid waste as well as 
different process for the feedstocks considered, like gasification of 
switchgrass and production of ``renewable'' diesel fuel through 
hydrotreating vegetable oils.
    Furthermore, the lifecycle analysis used for this rulemaking is 
based on averages of the different renewable fuels modeled. For 
example, the GHG emission and fossil energy savings associated with 
increased use of corn ethanol are calculated based on a mix of corn wet 
and dry milling, assuming a certain projected mix of each process. 
While this method may not exactly represent the reductions associated 
with a given gallon of renewable fuel, it is accurate for the purpose 
of this analysis which is to determine the impact of the total 
increased volume of renewable fuels used.
    We recognize that different feedstocks and processes will each have 
unique characteristics when it comes to lifecycle GHG emissions and 
energy use. However, we understand that other feedstocks and processes 
as well as differences in other parts of the renewable fuel lifecycle 
will impact the savings associated with their use and this is the focus 
of ongoing work at the agency.
b. Modifications to GREET
    Since the analysis done for the NPRM, we have updated the GREET 
model with the following changes:

--Included CO2 emissions from corn farming lime use.
--Updated the corn farming fertilizer use inputs.
--Added cellulosic biomass ethanol production from corn stover and 
forest waste.
--Modeled biomass as a process fuel source in corn ethanol dry milling.

    In addition to the changes listed above we also examined and 
updated other GREET input assumptions for corn ethanol and biodiesel 
production.
    We also examined several other GREET input values, but determined 
that the default GREET values should not be changed for a variety of 
reasons. These included, corn and ethanol transport distances and modes 
and byproduct allocation methods. Our investigation of these other 
GREET input values are discussed more fully in Chapter 6 of the RIA. 
The current GREET default factors for these other inputs were included 
in the analysis for this final rule.
    We did not investigate the input values associated with the 
production of petroleum-based gasoline or diesel fuel in the GREET 
model for this final rule. However, the refinery modeling discussed in 
Section VII provides some additional information on the process energy 
requirements associated with the production of gasoline and diesel 
under a renewable fuels mandate. We will use information from this 
refinery modeling in future analysis to determine if any GREET input 
values should be changed.
    A summary of the GREET input values we investigated and modified 
for the final rule analysis is given below.
    Corn Farming Energy Use: Corn farming energy use was updated based 
on the most recent USDA Agricultural Resource Management Survey (ARMS) 
data.
    CO2 from Land Use Change: The GREET model has a default factor for 
CO2 from land use change that was included in the NPRM 
analysis. This factor was updated based on the results of the 
agricultural sector modeling outlined in Section X. The CO2 
emissions from land use change used in the final rulemaking represents 
approximately 1% of total corn ethanol lifecycle GHG emissions. 
However, this value could be more significant if increased amounts of 
renewable fuels are used in the transportation sector. The issue of 
CO2 emissions from land use change associated with 
converting forest or Conservation Reserve Program (CRP) land into crop 
production for use in producing renewable fuels is an important factor 
to consider when determining the overall sustainability of renewable 
fuel use. While the analysis described above is indicating that the 
volumes of renewable fuel analyzed in this rulemaking will not cause a 
significant change in land use, this is an area we will continue to 
research for any future analysis.
    Corn Ethanol Wet-Mill Versus Dry Mill Plants: For this analysis, we 
expect most new ethanol plants will be dry mill operations. That has 
been the trend in the last few years as the demand for ethanol has 
grown, and our analysis of ethanol plants under construction and 
planned for the near future has verified this. Our analysis of 
production plans, as outlined in Section VI, indicates that essentially 
all new ethanol production will be from dry mill plants (99%).
    Corn Ethanol Dry Mill Plant Energy Use and Fuel Mix: Our review of 
plants under construction and those planned for the near future as 
outlined in Section VI, indicates that coal will be used as process 
fuel for approximately 14% of the new under construction and planned 
ethanol production volume capacity. The energy use at a dry mill plant 
using natural gas was based on the model developed by USDA and modified 
by EPA for use in the cost analysis of this rulemaking described in 
Section VII. For this analysis, we assumed that a coal plant would 
require 15% \111\ more electricity demand due to coal handling and have 
a 13% increase in thermal demand for steam dryers as compared to the 
natural gas fueled plant. We also considered a case where a corn 
ethanol plant utilized biomass as a fuel source. For this case we 
assumed the same amount of fuel and purchased electricity energy per 
gallon as a coal powered plant. This assumption is based on the biomass 
plant having more fuel handling than a natural gas plant and producing 
steam for DDGS drying.
---------------------------------------------------------------------------

    \111\ Baseline Energy Consumption Estimates for Natural Gas and 
Coal-based Ethanol Plants--The Potential Impact of Combined Heat and 
Power (CHP), Prepared for: U.S. Environmental Protection Agency 
Combined Heat & Power Partnership, Prepared by: Energy and 
Environmental Analysis, Inc., July 2006.
---------------------------------------------------------------------------

    Corn Ethanol Dry Mill Plant Production Yield: Modern ethanol plants 
are now able to produce more than 2.7 gallons of ethanol per bushel of 
corn compared with less than 2.4 gallons of ethanol per bushel of corn 
in 1980. The development of new enzymes continues to increase the 
potential ethanol yield. We used a value of

[[Page 23982]]

2.71 \112\ gal/bu in our analysis, which may underestimate actual 
future yields. For additional information on our yield analysis, see 
the cost modeling of corn ethanol discussed in Section VII.
---------------------------------------------------------------------------

    \112\ All yield values presented represent pure ethanol 
production (i.e. no denaturant).
---------------------------------------------------------------------------

    Corn Ethanol Co-Products: We based the amount of DDGS produced by 
an ethanol dry mill plant on the USDA model used in the cost analysis 
work of this rulemaking, described in Section VII. Based on the 
agricultural sector modeling outlined in Section X, we assumed that one 
ton of DDGS displaces 0.5 tons of corn and 0.5 tons of soybean meal. We 
also assume for corn ethanol wet milling that one ton of corn gluten 
meal substitutes for one ton of soybean meal, one ton of corn gluten 
feed substitutes for 0.5 tons of corn, and one ton of corn oil 
substitutes for one ton of soybean oil.
    Biodiesel Production: Two scenarios for biodiesel production were 
considered, one utilizing soybean oil as a feedstock and one using 
yellow grease. For the soybean oil scenario, the energy use and inputs 
for the biodiesel production process were based on a model developed by 
NREL and used by EPA in the cost modeling of soybean oil biodiesel, as 
discussed in Section VII. The GREET model does not have a specific case 
of biodiesel production from yellow grease. Therefore, as a surrogate 
we used the soybean oil based model with several adjustments. For the 
yellow grease case, we did not include soybean agriculture emissions or 
energy use. Soybean crushing was still included as a surrogate for 
yellow grease processing (purification, water removal, etc.). Also, due 
to additional processing requirements, the energy use associated with 
producing biodiesel from yellow grease is higher than for soybean oil 
biodiesel production. As per the cost modeling of yellow grease 
biodiesel discussed in Section VII, the energy use for yellow grease 
biodiesel production was assumed to be 1.72 times the energy used for 
soybean oil biodiesel.
    Biodiesel Transportation: Biodiesel transportation was based on the 
distribution infrastructure modeling for this rulemaking which 
indicates pipelines are not currently used to transport biodiesel and 
are not projected to play a role in biodiesel transport in the future 
time frame considered. Therefore, GREET default factors for biodiesel 
transportation from plant to terminal were modified to remove pipeline 
transport.
c. Sensitivity Analysis
    As mentioned above, the results of lifecycle analysis are highly 
dependent on the input data assumptions used. Section IX.A.1.b outlined 
changes made to the GREET model inputs to better represent the scope 
and purpose of our analysis for this rulemaking. However, we also 
performed several sensitivity analyses on some key assumptions to see 
how varying them would impact overall results.
    We performed a sensitivity analysis on expanding the lifecycle fuel 
production system boundaries to include farm equipment production 
(e.g., emissions and energy use associated with producing steel, 
rubber, etc. used to make farming equipment). It was found that 
including farm equipment production energy use and emissions increases 
ethanol lifecycle energy use and GHG emissions by approximately 1 
percent. Therefore, the lifecycle results are not changed significantly 
due to this expansion of system boundaries.
    We also performed a sensitivity analysis on the allocation method 
used in ethanol production. A number of by-products are made during the 
production of ethanol. In lifecycle analyses, the energy consumed and 
emissions generated by an ethanol plant must be allocated not only to 
ethanol, but also to each of the by-products. There are a number of 
methods that can be used to estimate by-product allocations. The 
displacement method for by-product allocation, described in Section 
6.1.2.10 of the RIA, is the default for the GREET model and is the 
method used by EPA. However, we evaluated another method, the process 
energy approach, to determine the impact this assumption has on the 
overall results of the analysis.
    Use of the process energy based allocation method reduces ethanol 
lifecycle energy use and GHG emissions by approximately 30 percent 
compared to the displacement allocation approach. This indicates that 
ethanol lifecycle analysis results are extremely sensitive to the 
choice of allocation method used. (See the RIA, Chapter 6 for more 
information on these two by-product allocation methods) The 
displacement allocation method is the method supported by international 
lifecycle assessment standards \113\ and therefore EPA feels that it is 
the most accurate and preferred method to use. This does however 
highlight the sensitivity of lifecycle analysis results to choice of 
input parameters and assumptions.
---------------------------------------------------------------------------

    \113\ ISO 14044:2006(E), ``Environmental Management--Life Cycle 
Assessment--Requirements and Guidelines'', International 
Organization for Standardization (ISO), First edition, 2006-07-01, 
Switzerland.
---------------------------------------------------------------------------

3. Displacement Indexes (DI)
    The displacement index (DI) represents the percent reduction in GHG 
emissions or fossil fuel energy brought about by the use of a renewable 
fuel in comparison to the conventional gasoline or diesel that the 
renewable fuel replaces. The formula for calculating the displacement 
index depends on which fuel is being displaced (i.e. gasoline or 
diesel), and which endpoint is of interest (e.g. petroleum energy, 
GHG). For instance, when investigating the CO2 impacts of 
ethanol used in gasoline, the displacement index is calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TR01MY07.058

    The units of g/Btu ensure that the comparison between the renewable 
fuel and the conventional fuel is made on a common basis, and that 
differences in the volumetric energy content of the fuels is taken into 
account. The denominator includes the CO2 emitted through 
combustion of the gasoline itself in addition to all the CO2 
emitted during its manufacturer and distribution. The numerator, in 
contrast, includes only the CO2 emitted during the 
manufacturer and distribution of ethanol, not the CO2 
emitted during combustion of the ethanol.
    The combustion of biomass-based fuels, such as ethanol from corn 
and woody crops, generates CO2. However, in the long run the 
CO2 emitted from biomass-based fuels combustion does not 
increase atmospheric CO2 concentrations, assuming the 
biogenic carbon emitted is offset by the uptake of CO2 
resulting from the growth of new biomass. Thus ethanol's carbon can be 
thought of as cycling from the environment into the plant material

[[Page 23983]]

used to make ethanol and, upon combustion of the ethanol, back into the 
environment from which it came. As a result, CO2 emissions 
from biomass-based fuels combustion are not included in their lifecycle 
emissions results and are not used in the CO2 displacement 
index calculations shown above. Net carbon fluxes from changes in 
biogenic carbon reservoirs in wooded or crop lands are accounted for 
separately in the GREET model.
    Using GREET, we calculated the lifecycle values for energy consumed 
and GHGs produced for corn-ethanol, cellulosic ethanol, and soybean-
based biodiesel. These values were in turn used to calculate the 
displacement indexes. The results are shown in Table IX.A.3-1. Details 
of these calculations can be found in Chapter 6 of the RIA.

                                                Table IX.A.3-1.--Displacement Indexes Derived From GREET
                                                                      [In percent]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    Corn ethanol       Cellulosic
                                                                  Corn ethanol     (biomass fuel)        ethanol      Imported ethanol      Biodiesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
DIFossil Fuel.................................................         39.4              76.3              92.7              69.0              61.5
DIPetroleum...................................................         91.8              92.0              91.7              92.0              91.2
DIGHG.........................................................         21.8              54.1              90.9              56.0              67.7
DICO2.........................................................         40.3              72.3             100.1              71.0              69.8
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The displacement indexes in this table represent the impact of 
replacing a Btu of gasoline or diesel with a Btu of renewable fuel. 
Thus, for instance, for every Btu of gasoline which is replaced by corn 
ethanol, the total lifecycle GHG emissions that would have been 
produced from that Btu of gasoline would be reduced by 21.8 percent. 
For every Btu of diesel which is replaced by biodiesel, the total 
lifecycle petroleum energy that would have been consumed as a result of 
burning that Btu of diesel fuel would be reduced by 91.2 percent.
    Consistent with the cost modeling done for this rule, for the 2012 
cases we assume the ``cellulosic'' ethanol volume is actually produced 
from corn utilizing a biomass fuel source at the ethanol production 
plant. The displacement index for that fuel as shown in Table IX.A.3-1 
is used in the calculation of reductions. We have included the column 
for cellulosic ethanol for comparison, indicating that a move toward 
cellulosic ethanol will not displace petroleum much differently than 
other renewable fuels but will have a positive impact on GHG emissions 
reductions.
    For imported ethanol, it is more difficult to estimate the 
lifecycle energy and GHG displacement indexes since we know much less 
about how the crops used to make the ethanol are grown and what energy 
is used in the ethanol production facility. While not exclusively, we 
anticipate much imported ethanol to be primarily sugarcane based 
ethanol.
    The GHG emissions when producing sugarcane ethanol differs from 
corn ethanol in that the GHG emissions from growing sugarcane is likely 
different than for growing a equivalent amount of corn to make a gallon 
of ethanol. Also, the process of turning sugar into ethanol is easier 
than when starting with starch and therefore less energy intensive 
(which typically translates into lower GHG). Importantly, we understand 
that at least some of the ethanol produced in Brazil uses the bagasse 
from the sugarcane itself as a process fuel source. We know from our 
analysis that using a biomass source for process energy greatly 
improves the GHG benefit of the renewable fuel. These factors would 
result in sugarcane ethanol having a greater GHG benefit per gallon 
than corn ethanol, certainly where natural gas or coal is the typical 
process fuel source used.
    Conversely, sugarcane ethanol production does not result in a co-
product such as distillers grain as in the case of corn ethanol. In our 
analyses, accounting for co-products significantly improved the GHG 
displacement index for corn ethanol. Furthermore, there would be 
additional transportation emissions associated with transporting the 
imported ethanol to the U.S. as compared to domestically produced 
ethanol. Developing a technically rigorous lifecycle estimate for 
energy needs and GHG impacts for imported ethanol is not a simple task 
and was not available in the timeframe of this rulemaking.
    Considering all of the differences between imported and domestic 
ethanol, for this rulemaking, we assumed imported ethanol would be 
predominately from sugarcane and have estimated DI's approximately mid-
way between the DI's for corn ethanol and DI's for cellulosic ethanol. 
We are continuing to develop a better understanding of the lifecycle 
energy and GHG impacts of producing ethanol from sugarcane and other 
likely feedstock sources of imported ethanol for any future analysis.
4. Impacts of Increased Renewable Fuel Use
    We used the methodology described above to evaluate impacts of 
increased use of renewable fuels on consumption of petroleum and fossil 
fuels and also on emissions of CO2 and GHGs. This section 
describes our results.
a. Greenhouse Gases and Carbon Dioxide
    We estimated the reduction associated with the increased use of 
renewable fuels on lifecycle emissions of CO2 and total GHG. 
Since total GHG emission reductions are lower than CO2 
reductions, this indicates that lifecycle emissions of CH4 
and N2O are higher for renewable fuels than for the 
conventional fuels replaced. These values are then compared to the U.S. 
transportation sector emissions to get a percent reduction. The 
estimates for the 2012 cases are presented in Table IX.A.4.a-1.

[[Page 23984]]



 Table IX.A.4.A-1.--Estimated CO2 and GHG Emission Impacts of Increased
Use of Renewable Fuels in the Transportation Sector in 2012, Relative to
                         the 2012 Reference Case
------------------------------------------------------------------------
                                               RFS case       EIA case
------------------------------------------------------------------------
CO2 Reduction (million metric tons CO2)...         11.0           19.5
Percent reduction in Transportation Sector          0.52           0.93
 CO Emissions.............................
GHG Reduction (million metric tons CO2-             8.0           13.1
 eq.).....................................
Percent reduction in Transportation Sector          0.36           0.59
 GHG Emissions............................
------------------------------------------------------------------------

b. Fossil Fuel and Petroleum
    We estimated the reduction associated with the increased use of 
renewable fuels on lifecycle fossil fuels and petroleum. These values 
are then compared to the U.S. transportation sector emissions to get a 
percent reduction. The estimates for the 2012 cases are presented in 
Table IX.A.4.b-1.

    Table IX.A.4.B-1.--Estimated Fossil Fuel and Petroleum Impacts of
 Increased Use of Renewable Fuels in the Transportation Sector in 2012,
                   Relative to the 2012 Reference Case
------------------------------------------------------------------------
                                               RFS case       EIA case
------------------------------------------------------------------------
Fossil Fuel Reduction (quadrillion Btu)...          0.15           0.27
Percent reduction in Transportation Sector          0.48           0.85
 Fossil Fuel Use..........................
Petroleum Energy Reduction (billion gal.).          2.0            3.9
Percent reduction in Transportation Sector          0.82           1.60
 Petroleum Use............................
------------------------------------------------------------------------

B. Implications of Reduced Imports of Petroleum Products

    In the proposal, we estimated the impact of expanded renewable fuel 
use on the importation of oil and finished transportation fuel. No 
comments were received suggesting alternative methodologies should be 
used. Therefore, we have incorporated that calculation in this final 
rule without change.
    In 2005, the United States imported almost 60 percent of the oil it 
consumed. This compares to just over 35 percent of oil from imports in 
1975.\114\ Transportation accounts for 70 percent of the U.S. oil 
consumption. It is clear that oil imports have a significant impact on 
the U.S. economy. Expanded production of renewable fuel is expected to 
contribute to energy diversification and the development of domestic 
sources of energy. We consider whether the RFS will reduce U.S. 
dependence on imported oil by calculating avoided expenditures on 
petroleum imports. Note that we do not calculate whether this reduction 
is on the net, socially beneficial, which would depend on the scarcity 
value of domestically produced ethanol versus that of imported 
petroleum products. However, the next section does discuss some of the 
energy security implications unique to petroleum imports.
---------------------------------------------------------------------------

    \114\ Davis, Stacy C.; Diegel, Susan W., Transportation Energy 
Data Book: 25th Edition, Oak Ridge National Laboratory, U.S. 
Department of Energy, ORNL-6974, 2006.
---------------------------------------------------------------------------

    To assess the impact of the RFS program on petroleum imports, we 
estimate the fraction of domestic consumption derived from foreign 
sources using results from the AEO 2006. We compared the levels and mix 
of imports in the AEO reference case with those in the low 
macroeconomic growth case and high oil price case. In Section 6.4.1 of 
the RIA we describe in greater detail how fuel producers may change 
their levels and mix of imports in response to a decrease in fuel 
demand. For the purposes of this rulemaking, we show values for the low 
macroeconomic growth comparison, where import reductions come almost 
entirely from imports of finished products as shown below in Table 
IX.B-1. The reductions in imports are compared to the AEO projected 
levels of net petroleum imports. The range of reductions in net 
petroleum imports are estimated to be between 0.9 to 1.7 percent, as 
shown in Table IX.B-1.

            Table IX.B-1.--Net Reductions in Imports in 2012
------------------------------------------------------------------------
                                                     RFS case   EIA case
------------------------------------------------------------------------
Reduction in finished products* (barrels per day).    123,000    240,000
Percent reduction**...............................      0.89%      1.73%
------------------------------------------------------------------------
* Net reductions relative to 2012 reference case.
** Compared to AEO 2006 projections for 2012 reference case.

    We also calculate the change in expenditures in both petroleum and 
ethanol imports and compare these with the U.S. trade position measured 
as U.S. net exports of all goods and services economy-wide. The 
decreased expenditures were calculated by multiplying the changes in 
gasoline, diesel, and ethanol imports by the respective AEO 2006 
wholesale gasoline, distillate, and ethanol price forecasts for the 
specific analysis years. In Table IX.B-2, the net expenditures in 
reduced petroleum imports, increased ethanol imports, and decreased 
corn exports are compared to the total value of U.S. net exports of 
goods and services for the whole economy for 2012. Relative to the 2012 
projection, the avoided expenditures due to the RFS would represent 0.4 
to 0.7% of economy-wide net exports.

[[Page 23985]]



                                               Table IX.B-2.--Avoided Import Expenditures ($2004 Billion)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                      Expenditures
                                                                                           on       Expenditures   Decreased        Net       Percent of
                      Cases                              AEO total net exports          petroleum    on ethanol       corn     expenditures   total net
                                                                                         imports       imports      exports     on  imports    exports
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS Case........................................  -$383 (year 2012).................         -$2.6         +$0.7        +$0.6         -$1.4         0.4%
EIA Case........................................  ..................................         -$5.1         +$1.0        +$1.3         -$2.8         0.7%
--------------------------------------------------------------------------------------------------------------------------------------------------------

C. Energy Security Implications of Increases in Renewable Fuels

    One of the effects of increased use of renewable fuels in the U.S. 
from the RFS is that it diversifies the energy sources in making 
transportation fuel. A potential disruption in supply reflected in the 
price volatility of a particular energy source carries with it both 
financial as well as strategic risks. These risks can be reduced to the 
extent that diverse sources of fuel energy reduce the dependence on any 
one source. This reduction in risks is a measure of improved energy 
security.
    At the time of the proposal, EPA stated that an analysis would be 
completed and estimates provided in support of this rule. In order to 
understand the energy security implications of the RFS, EPA has worked 
with Oak Ridge National Laboratory (ORNL), which has developed 
approaches for evaluating the social costs and energy security 
implications of oil use. In a new study produced for the RFS, entitled 
``The Energy Security Benefits of Reduced Oil Use, 2006-2015,'' ORNL 
has updated and applied the method used in the 1997 report ``Oil 
Imports: An Assessment of Benefits and Costs'', by Leiby, Jones, Curlee 
and Lee.115 116 While the 1997 report including a 
description of methodology and results at that time has been used or 
cited on a number of occasions, this updated analysis and results have 
not been available for full public consideration. Since energy security 
will be a key consideration in future actions aimed at reducing our 
dependence on oil, it is important to assure estimates of energy 
security impacts have been thoroughly examined in a full and open 
public forum. Since the updated analysis was only recently available, 
such a thorough analysis has not been possible. Therefore, EPA has 
decided to consider this update as a draft report, include it as part 
of the record of this rulemaking and invite further public analysis and 
consideration of both this particular draft report but also other 
perspectives on how to best quantify energy security benefits. To 
facilitate that additional consideration, we highlight below some of 
the key aspects of this particular draft analysis.
---------------------------------------------------------------------------

    \115\ Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and 
Russell Lee, Oil Imports: An Assessment of Benefits and Costs, ORNL-
6851, Oak Ridge National Laboratory, November, 1997.
    \116\ The 1997 ORNL paper was cited and its results used in DOT/
NHTSA's rules establishing CAFE standards for 2008 through 2011 
model year light trucks. See DOT/NHTSA, Final Regulatory Impacts 
Analysis: Corporate Average Fuel Economy and CAFE Reform MY 2008-
2011, March 2006.
---------------------------------------------------------------------------

    The approach developed by ORNL estimates the incremental benefits 
to society, in dollars per barrel, of reducing U.S. oil imports, called 
``oil premium.'' Since the 1997 publication of this report, changes in 
oil market conditions, both current and projected, suggest that the 
magnitude of the oil premium has changed. Significant driving factors 
that have been revised include: Oil prices, current and anticipated 
levels of OPEC production, U.S. import levels, the estimated 
responsiveness of regional oil supplies and demands to price, and the 
likelihood of oil supply disruptions. For this analysis, oil prices 
from the EIA's AEO 2006 were used. Using the ``oil premium'' approach, 
estimates of benefits of improved energy security from reduced U.S. oil 
imports from increased use of renewable fuels are calculated.
    In conducting this analysis, ORNL considered the full economic cost 
of importing petroleum into the U.S. The full economic cost of 
importing petroleum into the U.S. is defined for this analysis to 
include two components in addition to the purchase price of petroleum 
itself. These are: (1) The higher costs for oil imports resulting from 
the effect of U.S. import demand on the world oil price and OPEC market 
power (i.e., the so called ``demand'' or ``monoposony'' costs); and (2) 
the risk of reductions in U.S. economic output and disruption of the 
U.S. economy caused by sudden disruptions in the supply of imported oil 
to the U.S. (i.e., macroeconomic disruption/adjustment costs).
1. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and 
Economic Output
    The first component of the full economic costs of importing 
petroleum into the U.S. follows from the effect of U.S. import demand 
on the world oil price over the long-run. Because the U.S. is a 
sufficiently large purchaser of foreign oil supplies, its purchases can 
affect the world oil price. This monopsony power means that increases 
in U.S. petroleum demand can cause the world price of crude oil to 
rise, and conversely, that reduced U.S. petroleum demand can reduce the 
world price of crude oil. Thus, one consequence of decreasing U.S. oil 
purchases due to increased use of renewable fuel is the potential 
decrease in the crude oil price paid for all crude oil purchased.
2. Short-Run Disruption Premium From Expected Costs of Sudden Supply 
Disruptions
    The second component of the external economic costs resulting from 
U.S. oil imports arises from the vulnerability of the U.S. economy to 
oil shocks. The cost of shocks depends on their likelihood, size, and 
length, the capabilities of the market and U.S. Strategic Petroleum 
Reserve (SPR), the largest stockpile of government-owned emergency 
crude oil in the world, to respond, and the sensitivity of the U.S. 
economy to sudden price increases. While the total vulnerability of the 
U.S. economy to oil price shocks depends on the levels of both U.S. 
petroleum consumption and imports, variation in import levels or demand 
flexibility can affect the magnitude of potential increases in oil 
price due to supply disruptions. Disruptions are uncertain events, so 
the costs of alternative possible disruptions are weighted by 
disruption probabilities. The probabilities used by the ORNL study are 
based on a 2005 Energy Modeling Forum\117\ synthesis of expert judgment 
and are used to determine an expected value of disruption costs, and 
the change in those expected costs given reduced U.S. oil imports.
3. Costs of Existing U.S. Energy Security Policies
    The last often-identified component of the full economic costs of 
U.S. oil

[[Page 23986]]

imports is the costs to the U.S. taxpayers of existing U.S. energy 
security policies. The two primary examples are maintaining a military 
presence to help secure stable oil supply from potentially vulnerable 
regions of the world and maintaining the SPR to provide buffer supplies 
and help protect the U.S. economy from the consequences of global oil 
supply disruptions.
    U.S. military costs are excluded from the analysis performed by 
ORNL because their attribution to particular missions or activities is 
difficult. Most military forces serve a broad range of security and 
foreign policy objectives. Attempts to attribute some share of U.S. 
military costs to oil imports are further challenged by the need to 
estimate how those costs might vary with incremental variations in U.S. 
oil imports. Similarly, while the costs for building and maintaining 
the SPR are more clearly related to U.S. oil use and imports, 
historically these costs have not varied in response to changes in U.S. 
oil import levels. Thus, while SPR is factored into the ORNL analysis, 
the cost of maintaining the SPR is excluded.
    As stated earlier, we have placed the draft report in the docket of 
this rulemaking for the purposes of inviting further consideration. 
However, the draft results of that report have not been used in 
quantifying the impacts of this rule.

X. Agricultural Sector Economic Impacts

    As described in the Notice of Proposed Rulemaking (NPRM), we used 
the Forest and Agricultural Sector Optimization Model (FASOM) developed 
by Professor Bruce McCarl of Texas A&M University and others, to 
estimate the agricultural sector impacts of increasing renewable fuel 
volumes required by the RFS and for those volumes anticipated by EIA 
for 2012. Although current renewable fuel volume predictions are higher 
than the scenarios described in this rulemaking, we based our analysis 
on assumptions developed during the NPRM process. Our agricultural 
sector analysis considered the impacts of the domestic production of 
renewable fuels. Therefore, when we refer to either the RFS Case or the 
EIA Case, we include only renewable fuels produced from feedstocks 
grown in the U.S.\118\
    At the time the NPRM was published, we had not yet finished our 
analysis of the agricultural impacts associated with the RFS. In the 
NPRM, we stated our intent to have the analysis completed in time for 
the Final Rulemaking (FRM). In the proposal we described our plan to 
evaluate the effect of increasing renewable fuels volumes on U.S. 
commodity prices, renewable fuel byproduct prices, livestock feed 
sources, land use, exports, and farm income. The results of this 
analysis are summarized in this section. Additional details are 
included in the Regulatory Impact Analysis (RIA).
---------------------------------------------------------------------------

    \117\ Stanford Energy Modeling Forum, Phillip C. Beccue and 
Hillard G. Huntington, ``An Assessment of Oil Market Disruption 
Risks,'' Final Report, EMF SR 8, October, 2005.
    \118\ The RIA contains additional information on the renewable 
fuels volumes analyzed for this rulemaking.
---------------------------------------------------------------------------

    FASOM is a long-term economic model of the U.S. agriculture sector 
that attempts to maximize total revenues for producers while meeting 
the demands of consumers. Using a number of inputs, FASOM estimates 
which crops, livestock, and processed agricultural products will be 
produced in the U.S. The cost of these and other inputs are used to 
determine the price and level of production of commodities (e.g., field 
crops, livestock, and biofuel products). FASOM does not capture short-
term fluctuations (i.e., month-to-month, annual) in prices and 
production, however, as it is designed to identify long-term trends 
(i.e., five to ten years).
    FASOM predicts that as renewable fuel volumes increase, corn prices 
will rise by about 18 cents (RFS Case) and 39 cents (EIA Case) above 
the Reference Case price of $2.32 per bushel. For consistency, all of 
the dollar estimates are presented in 2004 dollars. Soybean prices will 
rise by about 18 cents (RFS Case) and 21 cents (EIA Case) above the 
Reference Case price of $5.26 per bushel by 2012. Since biodiesel 
volumes will not increase significantly in either the RFS or EIA 
scenarios, FASOM does not predict significant changes in the soybean 
related markets with respect to usage changes, or most other variables 
of interest for this rulemaking. The one exception is U.S. soybean 
exports, which are affected modestly.
    Changes in corn use can be seen by the changing percentage of corn 
used for ethanol. In 2005, approximately 12 percent of the corn supply 
was used for ethanol production, however we estimate the amount of corn 
used for ethanol in 2012 will increase to 20 percent (RFS Case) and 26 
percent (EIA Case).
    The rising price of corn and soybeans has a direct impact on how 
corn is used. Higher domestic corn prices lead to lower U.S. exports as 
the world markets shift to other sources of these products or expand 
the use of substitute grains. FASOM estimates that U.S. corn exports 
will drop from about 2 billion bushels in our Reference Case, to 1.6 
billion bushels (RFS Case) and 1.3 billion bushels (EIA Case) by 2012. 
U.S. exports of corn are estimated to drop by about 19 percent by 2012 
for the RFS Case and by roughly 38 percent in the EIA Case. In value 
terms, U.S. exports of corn fall by $573 million in the RFS Case and by 
$1.29 billion in the EIA Case in 2012.
    The impact on domestic livestock feed due to higher corn prices and 
higher U.S. demand for corn in ethanol is also partially offset by 
decreasing the use of corn for U.S. livestock feed. Substitutes are 
available for corn as a feedstock, and this market is price sensitive. 
One alternate feedstock is distillers dried grains with solubles 
(DDGS), a byproduct associated with the dry milling of ethanol 
production. Since FASOM predicts relatively flat prices for DDGS across 
all ethanol volume scenarios, the result is a significant increase in 
the use of DDGS as a feed source. We estimate DDGS in feed for the RFS 
case will almost double by 2012, increasing from 8.5 million tons to 
15.2 million tons. Under the EIA Case, we expect DDGS to increase to 
22.2 million tons by 2012.
    The increase in soybean prices is estimated to cause a decline in 
U.S. soybean exports. In terms of export earnings, U.S. exports of 
soybeans fall by $220 million in the RFS Case and by $194 million in 
the EIA Case in 2012.
    The increase in renewable fuel production provides a significant 
increase in net farm income to the U.S. agricultural sector. FASOM 
predicts that in 2012, net U.S. farm income will increase by $2.6 
billion dollars in the RFS renewable fuel volumes case (RFS Case) and 
$5.4 billion in the EIA renewable fuel volumes case (EIA Case). The RFS 
and EIA farm revenue increases represent roughly a 5 and 10 percent 
increase, respectively, in U.S. net farm income from the sale of farm 
commodities over the Reference Case of roughly $53 billion.
    Higher corn prices will have a direct impact on the value of U.S. 
agricultural land. As demand for corn and farm products increases, the 
price of U.S. farm land will also increase. Our analysis shows that in 
2012, higher renewable fuel volumes increase land prices by about 8 
percent (RFS Case) and 17 percent (EIA Case). Much of the high quality, 
suitable land in the U.S. is already being used to produce corn. FASOM 
estimates an increase of 1.6 million acres (RFS Case) and 2.6 million 
acres (EIA Case) above the 78.5 million corn acres harvested in the 
Reference Case in 2012. Due to this higher value of land, we are 
predicting that farms will withdraw a portion of the land currently in 
the Conservation Reserve Program (CRP), about 2.3 million acres (RFS 
Case) and 2.5 million acres (EIA

[[Page 23987]]

Case) out of the approximately 40 million acres in CRP.\119\
---------------------------------------------------------------------------

    \119\ Since much of the CRP land is ill suited for corn or 
soybean production, it is unlikely this land will go directly into 
corn or soybean production but instead will more likely be used to 
replace other agricultural land uses displaced by expanded corn and 
soybean production.
---------------------------------------------------------------------------

    FASOM estimates U.S. annual wholesale food costs will increase by 
approximately $2.2 billion with the RFS renewable volumes and $3.7 
billion with the EIA renewable volumes by 2012. These costs translate 
to approximately $7 per person per year (RFS case) and $12 per person 
per year (EIA case).
    In the proposal, we noted that expansion in the use of renewable 
fuels also raises the issue of whether water quality and rural 
ecosystems in general could be affected due to increased production of 
agricultural feedstocks used to produce greater volumes of renewable 
fuels. We received one comment from Marathon asserting that our 
environmental assessment was incomplete and did not address water 
quality issues. In the time frame to complete this rulemaking, we were 
not able to conduct a comprehensive assessment of the environmental 
impacts in the agricultural sector of the wider use of renewable fuels. 
However, we have considered two indicators--fertilizer use on 
agricultural crops and Conservation Resource Program (CRP) lands--that 
may relate to environmental quality and water quality from the 
production of renewable fuels. The CRP is a voluntary program 
administered by the U.S. Department of Agriculture that helps defray 
the costs to farmers of taking agricultural lands out of production and 
placing them in CRP to provide environmental protection.
    As discussed in Section X, FASOM predicts the total amount of 
nitrogen applied on all farms will increase by 1.2 percent in the RFS 
Case and by 2 percent in the EIA Case, relative to the Reference Case 
in 2012. The total amount of phosphorous applied on all farms increases 
by 0.7 percent in the RFS Case and 1.2 percent in the EIA Case, 
relative to the Reference Case in 2012. Currently, there are 
approximately 40 million acres in the CRP. FASOM predicts 2.3 million 
acres (RFS Case) and 2.5 million acres (EIA Case) of land would be 
withdrawn from the CRP due to higher land values.

XI. Public Participation

    Many interested parties participated in the rulemaking process that 
culminates with this final rule. This process provided opportunity for 
submitting written public comments following the proposal that we 
published on September 22, 2006 (71 FR 55552). We considered these 
comments in developing the final rule. In addition, we held a public 
hearing on the proposed rulemaking on October 13, 2006, and we have 
considered comments presented at the hearing.
    Throughout the rulemaking process, EPA met with stakeholders 
including representatives from the refining industry, renewable fuels 
production, and marketers and distributors, and others. The program we 
are finalizing today was developed as a collaborative effort with these 
stakeholders.
    We have prepared a detailed Summary and Analysis of Comments 
document, which describes comments we received on the proposal and our 
response to each of these comments. The Summary and Analysis of 
Comments is available in the docket for this rule at the Internet 
address listed under ADDRESSES, as well as on the Office of 
Transportation and Air Quality Web site (http://www.epa.gov/otaq/renewablefuels/index.htm
). In addition, comments and responses for key 

issues are included throughout this preamble.

XII. Administrative Requirements

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866, (58 FR 51735, October 4, 1993) 
this action is a ``significant regulatory action'' because of the 
policy implications of the final rule. Even though EPA has estimated 
that renewable fuel use through 2012 will be sufficient through the 
operation of market forces to meet the levels required in the standard, 
the final rule reflects the first renewable fuel mandate at the federal 
level. Accordingly, EPA submitted this action to the Office of 
Management and Budget (OMB) for review under EO 12866 and any changes 
made in response to OMB recommendations have been documented in the 
docket for this action.

B. Paperwork Reduction Act

    The information collection requirements in this final rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) prepared by EPA has been assigned 
EPA ICR number 2242.02. The information collection requirements are not 
enforceable until OMB approves them.
    The information is planned to be collected to ensure that the 
required amount of renewable fuel is used each year. The credit trading 
program required by the Energy Policy Act will be satisfied through a 
program utilizing Renewable Identification Numbers (RINs), which are 
assigned when renewable fuel is produced in or imported to geographic 
areas covered by the rule. Production and importation of renewable fuel 
will serve as a surrogate measure of renewable fuel consumption. Our 
final RIN-based program will fulfill all the functions of a credit 
trading program, and thus will meet the Energy Policy Act's 
requirements. For each calendar year, each obligated party will be 
required to submit a report to the Agency documenting the RINs it 
acquired, and showing that the sum of all RINs acquired is equal to or 
greater than its renewable volume obligation. The Agency could then 
verify that the RINs used for compliance purposes were valid by simply 
comparing RINs reported by producers to RINs claimed by obligated 
parties.
    For fuel standards, Section 208(a) of the Clean Air Act requires 
that manufacturers provide information the Administrator may reasonably 
require to determine compliance with the regulations; submission of the 
information is therefore mandatory. We will consider confidential all 
information meeting the requirements of Section 208(c) of the Clean Air 
Act.
    The annual public reporting and recordkeeping burden for this 
collection of information is estimated to be 3.3 hours per response. A 
document entitled ``Information Collection Request (ICR); OMB-83 
Supporting Statement, Environmental Protection Agency, Office of Air 
and Radiation,'' has been placed in the public docket. The supporting 
statement provides a detailed explanation of the Agency's estimates by 
collection activity and explains how comments may be submitted by 
interested parties. The estimates contained in the docket are briefly 
summarized here:
    Estimated total number of potential respondents: 6,425.
    Estimated total number of responses: 13,380.
    Estimated total annual burden hours: 43,030.
    Estimated total respondent cost (estimated at $71 per hour): 
$3,055,130.
    Estimated total non-postage purchased services (estimated at $142 
per hour): $5,219,920.
    EPA received various comments on the rulemaking provisions covered 
by the proposed ICR. All comments that were submitted to EPA are 
considered in the Summary and Analysis of Comments, which can be found 
in the

[[Page 23988]]

docket. In response to comments, we have increased the frequency of 
reporting for transaction and summary reports from annually to 
quarterly. We have also removed a burden for small refiners that was 
associated with applying for small-refiner flexibilities. The burdens 
and costs shown above account for these changes.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is 
approved by OMB, the Agency will publish a technical amendment to 40 
CFR part 9 in the Federal Register to display the OMB control number 
for the approved information collection requirements contained in this 
final rule.

C. Regulatory Flexibility Act

1. Overview
    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's (SBA) regulations at 13 CFR 
121.201 (see table below); (2) a small governmental jurisdiction that 
is a government of a city, county, town, school district or special 
district with a population of less than 50,000; and (3) a small 
organization that is any not-for-profit enterprise which is 
independently owned and operated and is not dominant in its field. The 
following table provides an overview of the primary SBA small business 
categories potentially affected by this regulation:
---------------------------------------------------------------------------

    \120\ In the NPRM, we also referred to a 125,000 barrels of 
crude per day (bpcd) crude capacity limit. This criterion was 
inadvertently used and is not applicable for this program (as it 
only applies in cases of government procurement). We note that the 
number of small entities remains the same whether this criterion is 
used or not.

------------------------------------------------------------------------
                                        Defined as small     NAICS codes
              Industry                  entity by SBA if         \a\
------------------------------------------------------------------------
Gasoline refiners..................  < =1,500                     324110
                                      employees.\120\.
------------------------------------------------------------------------
\a\ North American Industrial Classification System.

    EPA has determined that it is not necessary to prepare a regulatory 
flexibility analysis in connection with this final rule.
2. Background
    Since the vast majority of crude oil produced in or imported into 
the U.S. is consumed as gasoline or diesel fuel, concerns about our 
dependence on foreign sources of crude oil has renewed interest in 
renewable transportation fuels. The passage of the Energy Policy Act of 
2005 demonstrated a strong commitment on the part of U.S. policymakers 
to consider additional means of supporting renewable fuels as a 
supplement to petroleum-based fuels in the transportation sector. 
Section 1501 of the Energy Policy Act, which was added to the CAA as 
Section 211(o), requires EPA to establish the RFS program to ensure 
that the pool of gasoline sold in the contiguous 48 states contains 
specific volumes of renewable fuel for each calendar year starting with 
2006. The Agency is required to set a standard for each year 
representing the amount of renewable fuel that obligated parties (e.g., 
refiners, blenders, and importers) must use as a percentage of gasoline 
sold or introduced into commerce, and the Agency is required to 
promulgate a credit trading program for the RFS program.
3. Small Refineries Versus Small Refiners
    Title XV (Ethanol and Motor Fuels) of the Energy Policy Act 
provides, at Section 1501(a)(2) [42 U.S.C. 7545(o)(9)(A)-(D)], special 
provisions for ``small refineries'', such as a temporary exemption from 
the standards until calendar year 2011. The Act defines the term 
``small refinery'' as ``* * * a refinery for which the average 
aggregate daily crude oil throughput for a calendar year * * * does not 
exceed 75,000 barrels.'' As shown in the table above, this term is 
different than SBA's small business category for gasoline refiners, 
which is what the Regulatory Flexibility Act is concerned with. EPA is 
required under the RFA to consider impacts on small entities meeting 
SBA's small business definition; these entities are referred to as 
``small refiners'' for our regulatory flexibility analysis under 
SBREFA.
    A small refinery, per the Energy Policy Act, is a refinery where 
the annual crude throughput is less than or equal to 75,000 barrels 
(i.e., a small-capacity refinery), and could be owned by a larger 
refiner that exceeds SBA's small entity size standards. The small 
business employee criteria were established for SBA's small business 
definition to set apart those companies which are most likely to be at 
an inherent economic disadvantage relative to larger businesses.
4. Summary of Potentially Affected Small Entities
    The refiners that are potentially affected by this rule are those 
that produce gasoline. For our recent final rule ``Control of Hazardous 
Air Pollutants From Mobile Sources'' (72 FR 8428, February 26, 2007), 
we performed an industry characterization of potentially affected 
gasoline refiners. We used that industry characterization to determine 
which refiners would also meet the SBA definition of a small entity. 
From that industry characterization, and further analysis following the 
Notice of Proposed Rulemaking (71 FR 55552, September 22, 2006), we 
have determined that there are 15 gasoline refiners who own 16 
refineries (14 refiners own one refinery each, the remaining refiner 
owns two refineries) that meet the definition of a small refiner. Of 
the 16 refineries, 13 also meet the Energy Policy Act's definition of a 
small refinery.
5. Impact of the Regulations on Small Entities
    As previously stated, many aspects of the RFS program, such as the 
required amount of annual renewable fuel volumes, are specified in the 
Energy Policy Act. As discussed above in Section II.A.1, the annual 
projections of ethanol production to satisfy market demand exceed the 
required annual renewable fuel volumes. When the small refinery 
exemption ends, it is anticipated that there will be over one

[[Page 23989]]

billion gallons in excess RINs available. We believe that this large 
volume of excess RINs will also lower the costs of this program. Thus, 
with the short-term relief provided under the Energy Policy Act for 
small refineries, and the anticipated low cost of RINs when the 
exemption expires, we believe that this program will not impose a 
significant economic burden on small refineries, small refiners, or any 
other obligated party. Therefore, we have determined that this rule 
will not have a significant economic impact on a substantial number of 
small entities.
    When the Agency certifies that a rule will not have a significant 
economic impact on a substantial number of small entities, EPA's policy 
is to make an assessment of the rule's impact on any small entities and 
to engage the potentially regulated entities in a dialog regarding the 
rule, and minimize the impact to the extent feasible. The following 
sections discuss our outreach with the potentially affected small 
entities and regulatory flexibilities to decrease the burden on these 
entities in compliance with the requirements of the RFS program.
6. Small Refiner Outreach
    We do not believe that the RFS program would have a significant 
economic impact on a substantial number of small entities, however we 
have still tried to reduce the impact of this rule on small entities. 
Prior to issuing the proposed rule, we held meetings with small 
refiners to discuss the requirements of the RFS program and the special 
provisions offered by the Energy Policy Act for small refineries.
    The Energy Policy Act set out the following provisions for small 
refineries:
     A temporary exemption from the Renewable Fuels Standard 
requirement until 2011;
     An extension of the temporary exemption period for at 
least two years for any small refinery where it is determined that the 
refinery would be subject to a disproportionate economic hardship if 
required to comply;
     Any small refinery may petition, at any time, for an 
exemption based on disproportionate economic hardship; and,
     A small refinery may waive its temporary exemption to 
participate in the credit generation program, or it may also ``opt-
in'', by waiving its temporary exemption, to be subject to the RFS 
requirement.
    During these meetings with the small refiners we also discussed the 
impacts of these provisions being offered to small refineries only. 
Three refiners met the definition of a small refiner, but their 
refineries did not meet the Act's definition of a small refinery; which 
naturally concerned the small refiners. Another concern that the small 
refiners had was that if this rule were to have a significant economic 
impact on a substantial number of small entities a lengthy SBREFA 
process would ensue (which would delay the promulgation of the RFS 
rulemaking) and thus provide less lead time for these small entities 
prior to the RFS program start date.
    Following our discussions with the small refiners, they provided 
three suggested regulatory flexibility options that they believed could 
further assist affected small entities in complying with the RFS 
program standard: (1) That all small refiners be afforded the Act's 
small refinery temporary exemption, (2) that small refiners be allowed 
to generate credits if they elect to comply with the RFS program 
standard prior to the 2011 small refinery compliance date, and (3) 
relieve small refiners who generate blending credits of the RFS program 
compliance requirements.
    We agreed with the small refiners' suggestion that small refiners 
be afforded the same temporary exemption that the Act specifies for 
small refineries. This relief would apply to refiners who meet the 
1,500 employee count criteria, as well as the crude capacity criteria 
that we have used in previous fuels programs when providing relief for 
small refiners. Regarding the small refiners' second and third 
suggestions regarding credits, we note that the RIN-based program will 
automatically provide them with credit for any renewables that they 
blend into their motor fuels. Until 2011, small refiners will 
essentially be treated as oxygenate blenders and may separate RINs from 
batches and trade or sell these RINs, unless they choose to opt-in to 
the program.
7. Reporting, Recordkeeping, and Compliance Requirements
    Registration, recordkeeping and reporting are necessary to track 
compliance with the renewable fuels standard and transactions involving 
RINs, and these compliance requirements will be similar to those 
required under our previous and current 40 CFR part 80 fuel compliance 
programs. We will use the same basic forms for RFS program registration 
that we use under the reformulated gasoline (RFG) and anti-dumping 
program, as these forms are well known in the regulated community and 
are simple to fill out. We will use a simplified method of reporting 
via the Agency's Central Data Exchange (CDX), which will reduce the 
reporting burden on regulated parties. Records related to RIN 
transactions may be kept in any format and the period of record 
retention by reporting parties is five years, similar to other fuel 
programs. Records to be retained include copies of all compliance 
reports submitted to EPA and copies of product transfer documents 
(PTDs). Sections IV and V, above, contain more detailed discussions on 
the registration, recordkeeping, reporting, and compliance requirements 
of this final rule.
8. Related Federal Rules
    We are aware of a few other current or proposed Federal rules that 
are related to this rule. The primary related federal rules are the 
Mobile Source Air Toxics (MSAT2) rule (72 FR 8428, February 26, 2007), 
the Tier 2 Vehicle/Gasoline Sulfur rulemaking (65 FR 6698, February 10, 
2000), and the fuel sulfur rules for highway diesel (66 FR 5002, 
January 18, 2001) and nonroad diesel (69 FR 38958, June 29, 2004).
9. Conclusions
    As stated above, based on the statutory relief provided by the 
Energy Policy Act for small refineries, we are certifying that this 
rule will not have a significant economic impact on a substantial 
number of small entities. Additionally, we believe that extending the 
small refinery exemption to small refiners would further reduce the 
economic impacts on small entities. We believe that small refiners 
generally lack the resources available to larger companies, and 
therefore find it appropriate to extend this exemption to all small 
refiners. Thus, we are extending the small refinery temporary exemption 
to all qualified small refiners. Small refiners will also be permitted 
to separate RINs from batches and trade or sell these RINs prior to 
2011 if the small refiner operates as an ethanol blender.
    Past fuels rulemakings have included a provision that, for the 
purposes of the regulatory flexibility provisions for small entities, a 
refiner must also have an average crude capacity of no more than 
155,000 barrels of crude per day (bpcd). To be consistent with these 
previous rules, we are finalizing in this rule that refiners that meet 
this criterion (in addition to having no more than 1,500 total 
corporate employees) will be considered small refiners for the purposes 
of the regulatory flexibility provisions for this rulemaking.
    Since the RFS program would have no significant economic impact on 
a substantial number of small entities

[[Page 23990]]

with only the relief required in the Energy Policy Act for small 
refineries, it also follows that the rule will have no significant 
economic impact on a substantial number of small entities with the 
additional relief this final rule provides for small refiners.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted.
    Before EPA establishes any regulatory requirements that may 
significantly or uniquely affect small governments, including tribal 
governments, it must have developed under Section 203 of the UMRA a 
small government agency plan. The plan must provide for notifying 
potentially affected small governments, enabling officials of affected 
small governments to have meaningful and timely input in the 
development of EPA regulatory programs with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    EPA has determined that this rule does not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate, or the private 
sector in any one year. EPA has estimated that renewable fuel use 
through 2012 will be sufficient to meet the required levels. Therefore, 
individual refiners, blenders, and importers are already on track to 
meet rule obligations through normal market-driven incentives. Thus, 
today's rule is not subject to the requirements of Sections 202 and 205 
of the UMRA.
    EPA has determined that this rule contains no regulatory 
requirements that might significantly or uniquely affect small 
governments. Compliance with the mandates of the RFS rule, including 
the reporting and recordkeeping requirements, are the responsibility of 
exporters, producers, and importers of renewable fuel and gasoline, and 
not small governments.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August 
10, 1999), requires EPA to develop an accountable process to ensure 
``meaningful and timely input by State and local officials in the 
development of regulatory policies that have federalism implications.'' 
``Policies that have federalism implications'' is defined in the 
Executive Order to include regulations that have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.''
    This final rule does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. Thus, Executive Order 13132 does 
not apply to this rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicited comment on the proposed rule 
from State and local officials. A number of states commented on the 
proposed rule. These comments are available in the rulemaking docket, 
and are summarized and addressed in the Summary and Analysis document.

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

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000), 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by tribal officials in the development of regulatory 
policies that have tribal implications.'' This final rule does not have 
tribal implications, as specified in Executive Order 13175. This rule 
will be implemented at the Federal level and will apply to refiners, 
blenders, and importers. Tribal governments will be affected only to 
the extent they purchase and use regulated fuels. Thus, Executive Order 
13175 does not apply to this rule.

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

    Executive Order 13045: ``Protection of Children from Environmental 
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies 
to any rule that: (1) Is determined to be ``economically significant'' 
as defined under Executive Order 12866, and (2) concerns an 
environmental health or safety risk that EPA has reason to believe may 
have a disproportionate effect on children. If the regulatory action 
meets both criteria, the Agency must evaluate the environmental health 
or safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency.
    EPA interprets EO 13045 as applying only to those regulatory 
actions that concern health or safety risks, such that the analysis 
required under section 5-501 of the EO has the potential to influence 
the regulation. This final rule is not subject to EO 13045 because it 
does not establish an environmental standard intended to mitigate 
health or safety risks and because it implements specific standards 
established by Congress in statutes.

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

    This rule is not a ``significant energy action'' as defined in 
Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355 
(May 22, 2001)) because it is not likely to have a significant adverse 
effect on the supply, distribution, or use of energy.
    EPA expects the provisions to have very little effect on the 
national fuel supply since normal market forces alone are promoting 
greater renewable fuel use than required by the RFS mandate. We discuss 
our analysis of the energy and supply effects of the increased use of 
renewable fuels in Sections VI and X of this preamble.

I. National Technology Transfer Advancement Act

    As noted in the proposed rule, Section 12(d) of the National 
Technology Transfer and Advancement Act of 1995 (``NTTAA''), Public Law 
No. 104-113, 12(d) (15 U.S.C. 272 note)

[[Page 23991]]

directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. The NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This rulemaking involves technical standards. EPA has decided to 
use ASTM D6751-06a ``Standard Specification for Biodiesel Fuel Blend 
Stock (B100) for Middle Distillate Fuels''. This standard was developed 
by ASTM International (originally known as the American Society for 
Testing and Materials), Subcommittee D02.E0, and was approved in August 
2006. The standard may be obtained through the ASTM Web site 
(http://www.astm.org) or by calling ASTM at (610) 832-9585. ASTM D6751-06a 

meets the objectives of this final rule because it establishes one of 
the criteria by which biodiesel is defined.

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA lacks the discretionary authority to address environmental 
justice in this final rulemaking since the Agency is implementing 
specific standards established by Congress in statutes. Although EPA 
lacks authority to modify today's regulatory decision on the basis of 
environmental justice considerations, EPA nevertheless determined that 
this final rule does not have a disproportionately high and adverse 
human health or environmental impact on minority or low-income 
populations.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A Major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). The effective date of the rule is September 1, 2007.

L. Clean Air Act Section 307(d)

    This rule is subject to Section 307(d) of the CAA. Section 
307(d)(7)(B) provides that ``[o]nly an objection to a rule or procedure 
which was raised with reasonable specificity during the period for 
public comment (including any public hearing) may be raised during 
judicial review.'' This section also provides a mechanism for the EPA 
to convene a proceeding for reconsideration, ``[i]f the person raising 
an objection can demonstrate to the EPA that it was impracticable to 
raise such objection within [the period for public comment] or if the 
grounds for such objection arose after the period for public comment 
(but within the time specified for judicial review) and if such 
objection is of central relevance to the outcome of the rule.'' Any 
person seeking to make such a demonstration to the EPA should submit a 
Petition for Reconsideration to the Office of the Administrator, U.S. 
EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., 
Washington, DC 20460, with a copy to both the person(s) listed in the 
preceding FOR FURTHER INFORMATION CONTACT section, and the Director of 
the Air and Radiation Law Office, Office of General Counsel (Mail Code 
2344A), U.S. EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460.

XIII. Statutory Authority

    Statutory authority for the rules finalized today can be found in 
section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support 
for the procedural and compliance related aspects of today's rule, 
including the recordkeeping requirements, come from Sections 114, 208, 
and 301(a) of the CAA, 42 U.S.C. 7414, 7542, and 7601(a).

List of Subjects in 40 CFR Part 80

    Environmental protection, Air pollution control, Fuel additives, 
Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle 
pollution, Penalties, Reporting and recordkeeping requirements.

    Dated: April 10, 2007.
Stephen L. Johnson,
Administrator.

0
40 CFR part 80 is amended as follows:

PART 80--REGULATION OF FUEL AND FUEL ADDITIVES

0
1. The authority citation for part 80 continues to read as follows:

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


0
2. Section 80.1100 is revised to read as follows:


Sec.  80.1100  How is the statutory default requirement for 2006 
implemented?

    (a) Definitions. For calendar year 2006, the definitions of section 
80.2 and the following additional definitions apply to this section.
    (1) Renewable fuel. (i) Renewable fuel means motor vehicle fuel 
that is used to replace or reduce the quantity of fossil fuel present 
in a fuel mixture used to operate a motor vehicle, and which:
    (A) Is produced from grain, starch, oil seeds, vegetable, animal, 
or fish materials including fats, greases, and oils, sugarcane, sugar 
beets, sugar components, tobacco, potatoes, or other biomass; or
    (B) Is natural gas produced from a biogas source, including a 
landfill, sewage waste treatment plant, feedlot, or other place where 
decaying organic material is found.
    (ii) The term ``renewable fuel'' includes cellulosic biomass 
ethanol, waste derived ethanol, biodiesel, and any blending components 
derived from renewable fuel.
    (2) Cellulosic biomass ethanol means ethanol derived from any 
lignocellulosic or hemicellulosic matter that is available on a 
renewable or recurring basis, including dedicated energy crops and 
trees, wood and wood residues, plants, grasses, agricultural residues, 
fibers, animal wastes and other waste materials, and municipal solid 
waste. The term also includes any ethanol produced in facilities where 
animal wastes or other waste materials are digested or otherwise used 
to displace 90 percent or more of the fossil fuel normally used in the 
production of ethanol.
    (3) Waste derived ethanol means ethanol derived from animal wastes, 
including poultry fats and poultry wastes, and other waste materials, 
or municipal solid waste.
    (4) Small refinery means a refinery for which the average aggregate 
daily crude

[[Page 23992]]

oil throughput for a calendar year (as determined by dividing the 
aggregate throughput for the calendar year by the number of days in the 
calendar year) does not exceed 75,000 barrels.
    (5) Biodiesel means a diesel fuel substitute produced from 
nonpetroleum renewable resources that meets the registration 
requirements for fuels and fuel additives established by the 
Environmental Protection Agency under section 211 of the Clean Air Act. 
It includes biodiesel derived from animal wastes (including poultry 
fats and poultry wastes) and other waste materials, or biodiesel 
derived from municipal solid waste and sludges and oils derived from 
wastewater and the treatment of wastewater.
    (b) Renewable Fuel Standard for 2006. The percentage of renewable 
fuel in the total volume of gasoline sold or dispensed to consumers in 
2006 in the United States shall be a minimum of 2.78 percent on an 
annual average volume basis.
    (c) Responsible parties. Parties collectively responsible for 
attainment of the standard in paragraph (b) of this section are 
refiners (including blenders) and importers of gasoline. However, a 
party that is a refiner only because he owns or operates a small 
refinery is exempt from this responsibility.
    (d) EPA determination of attainment. EPA will determine after the 
close of 2006 whether or not the requirement in paragraph (b) of this 
section has been met. EPA will base this determination on information 
routinely published by the Energy Information Administration on the 
annual domestic volume of gasoline sold or dispensed to U.S. consumers 
and of ethanol produced for use in such gasoline, supplemented by 
readily available information concerning the use in motor fuel of other 
renewable fuels such as cellulosic biomass ethanol, waste derived 
ethanol, biodiesel, and other non-ethanol renewable fuels.
    (1) The renewable fuel volume will equal the sum of all renewable 
fuel volumes used in motor fuel, provided that:
    (i) One gallon of cellulosic biomass ethanol or waste derived 
ethanol shall be considered to be the equivalent of 2.5 gallons of 
renewable fuel; and
    (ii) Only the renewable fuel portion of blending components derived 
from renewable fuel shall be counted towards the renewable fuel volume.
    (2) If the nationwide average volume percent of renewable fuel in 
gasoline in 2006 is equal to or greater than the standard in paragraph 
(b) of this section, the standard has been met.
    (e) Consequence of nonattainment in 2006. In the event that EPA 
determines that the requirement in paragraph (b) of this section has 
not been attained in 2006, a deficit carryover volume shall be added to 
the renewable fuel volume obligation for 2007 for use in calculating 
the standard applicable to gasoline in 2007.
    (1) The deficit carryover volume shall be calculated as follows:


DC = Vgas * (Rs-Ra)

Where:

DC = Deficit carryover, in gallons, of renewable fuel.
Vgas = Volume of gasoline sold or dispensed to U.S. consumers in 
2006, in gallons.
Rs = 0.0278.
Ra = Ratio of renewable fuel volume divided by total gasoline volume 
determined in accordance with paragraph (d)(2) of this section.

    (2) There shall be no other consequence of failure to attain the 
standard in paragraph (b) of this section in 2006 for any of the 
parties in paragraph (c) of this section.


0
3. Section 80.1101 is added to read as follows:


Sec.  80.1101  Definitions.

    The definitions of Sec.  80.2 and the following additional 
definitions apply for the purposes of this subpart. For calendar year 
2007 and beyond, the definitions in this section Sec.  80.1101 supplant 
those in Sec.  80.1100.
    (a) Cellulosic biomass ethanol means either of the following:
    (1) Ethanol derived from any lignocellulosic or hemicellulosic 
matter that is available on a renewable or recurring basis and includes 
any of the following:
    (i) Dedicated energy crops and trees.
    (ii) Wood and wood residues.
    (iii) Plants.
    (iv) Grasses.
    (v) Agricultural residues.
    (vi) Animal wastes and other waste materials, the latter of which 
may include waste materials that are residues (e.g., residual tops, 
branches, and limbs from a tree farm).
    (vii) Municipal solid waste.
    (2) Ethanol made at facilities at which animal wastes or other 
waste materials are digested or otherwise used onsite to displace 90 
percent or more of the fossil fuel that is combusted to produce thermal 
energy integral to the process of making ethanol, by:
    (i) The direct combustion of the waste materials or a byproduct 
resulting from digestion of such waste materials (e.g., methane from 
animal wastes) to make thermal energy; and/or
    (ii) The use of waste heat captured from an off-site combustion 
process as a source of thermal energy.
    (b) Waste derived ethanol means ethanol derived from either of the 
following:
    (1) Animal wastes, including poultry fats and poultry wastes, and 
other waste materials.
    (2) Municipal solid waste.
    (c) Biogas means methane or other hydrocarbon gas produced from 
decaying organic material, including landfills, sewage waste treatment 
plants, and animal feedlots.
    (d) Renewable fuel. (1) Renewable fuel is 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, and is produced from 
any of the following:
    (i) Grain.
    (ii) Starch.
    (iii) Oilseeds.
    (iv) Vegetable, animal, or fish materials including fats, greases, 
and oils.
    (v) Sugarcane.
    (vi) Sugar beets.
    (vii) Sugar components.
    (viii) Tobacco.
    (ix) Potatoes.
    (x) Other biomass.
    (xi) Natural gas produced from a biogas source, including a 
landfill, sewage waste treatment plant, feedlot, or other place where 
there is decaying organic material.
    (2) The term ``Renewable fuel'' includes cellulosic biomass 
ethanol, waste derived ethanol, biodiesel (mono-alky ester), non-ester 
renewable diesel, and blending components derived from renewable fuel.
    (3) Ethanol covered by this definition shall be denatured as 
required and defined in 27 CFR parts 20 and 21.
    (4) Small volume additives (excluding denaturants) less than 1.0 
percent of the total volume of a renewable fuel shall be counted as 
part of the total renewable fuel volume.
    (5) A fuel produced by a renewable fuel producer that is used in 
boilers or heaters is not a motor vehicle fuel and therefore is not a 
renewable fuel.
    (e) Blending component has the same meaning as ``Gasoline blending 
stock, blendstock, or component'' as defined at Sec.  80.2(s), for 
which the portion that can be counted as renewable fuel is calculated 
as set forth in Sec.  80.1115(a).
    (f) Motor vehicle has the meaning given in Section 216(2) of the 
Clean Air Act (42 U.S.C. 7550).
    (g) Small refinery means a refinery for which the average aggregate 
daily crude oil throughput for the calendar year 2004 (as determined by 
dividing the

[[Page 23993]]

aggregate throughput for the calendar year by the number of days in the 
calendar year) does not exceed 75,000 barrels.
    (h) Biodiesel (mono-alkyl ester) means a motor vehicle fuel or fuel 
additive which is all the following:
    (1) Registered as a motor vehicle fuel or fuel additive under 40 
CFR part 79.
    (2) A mono-alkyl ester.
    (3) Meets ASTM D-6751-07, entitled ``Standard Specification for 
Biodiesel Fuel Blendstock (B100) for Middle Distillate Fuels.'' ASTM D-
6751-07 is incorporated by reference. This incorporation by reference 
was approved by the Director of the Federal Register in accordance with 
5 U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the 
American Society for Testing and Materials, 100 Barr Harbor Drive, West 
Conshohocken, Pennsylvania. A copy may be inspected at the EPA Docket 
Center, Docket No. EPA-HQ-OAR-2005-0161, EPA/DC, EPA West, Room 3334, 
1301 Constitution Ave., NW., Washington, DC, or at the National 
Archives and Records Administration (NARA). For information on the 
availability of this material at NARA, call 202-741-6030, or go to: 
http://www.archives.gov/federal-register/cfr/ibr-locations.html.

    (4) Intended for use in engines that are designed to run on 
conventional diesel fuel.
    (5) Derived from nonpetroleum renewable resources (as defined in 
paragraph (m) of this section).
    (i) Non-ester renewable diesel means a motor vehicle fuel or fuel 
additive which is all the following:
    (1) Registered as a motor vehicle fuel or fuel additive under 40 
CFR part 79.
    (2) Not a mono-alkyl ester.
    (3) Intended for use in engines that are designed to run on 
conventional diesel fuel.
    (4) Derived from nonpetroleum renewable resources (as defined in 
paragraph (m) of this section).
    (j) Renewable crude means biologically derived liquid feedstocks 
including but not limited to poultry fats, poultry wastes, vegetable 
oil, and greases that are used as feedstocks to make gasoline or diesel 
fuels at production units as specified in paragraph (k) of this 
section.
    (k) Renewable crude-based fuels are renewable fuels that are 
gasoline or diesel products resulting from the processing of renewable 
crudes in production units within refineries or at dedicated facilities 
within refineries, that process petroleum based feedstocks and which 
make gasoline and diesel fuel.
    (l) Importers. For the purposes of this subpart only, an importer 
of gasoline or renewable fuel is:
    (1) Any person who brings gasoline or renewable fuel into the 48 
contiguous states of the United States from a foreign country or from 
an area that has not opted in to the program requirements of this 
subpart pursuant to Sec.  80.1143; and
    (2) Any person who brings gasoline or renewable fuel into an area 
that has opted in to the program requirements of this subpart pursuant 
to Sec.  80.1143.
    (m) Nonpetroleum renewable resources include, but are not limited 
to the following:
    (1) Plant oils.
    (2) Animal fats and animal wastes, including poultry fats and 
poultry wastes, and other waste materials.
    (3) Municipal solid waste and sludges and oils derived from 
wastewater and the treatment of wastewater.
    (n) Export of renewable fuel means:
    (1) Transfer of a batch of renewable fuel to a location outside the 
United States; and
    (2) Transfer of a batch of renewable fuel from a location in the 
contiguous 48 states to Alaska, Hawaii, or a United States territory, 
unless that state or territory has received an approval from the 
Administrator to opt-in to the renewable fuel program pursuant to Sec.  
80.1143.
    (o) Renewable Identification Number (RIN), is a unique number 
generated to represent a volume of renewable fuel pursuant to 
Sec. Sec.  80.1125 and 80.1126.
    (1) Gallon-RIN is a RIN that represents an individual gallon of 
renewable fuel; and
    (2) Batch-RIN is a RIN that represents multiple gallon-RINs.
    (p) Neat renewable fuel is a renewable fuel to which only de 
minimus amounts of conventional gasoline or diesel have been added.


Sec. Sec.  80.1102 through 80.1103  [Reserved]

0
4. Sections 80.1102 and 80.1103 are reserved.

0
5. Sections 80.1104 through 80.1107 are added to read as follows:

Subpart K--Renewable Fuel Standard

* * * * *
Sec.
80.1104 What are the implementation dates for the Renewable Fuel 
Standard Program?
80.1105 What is the Renewable Fuel Standard?
80.1106 To whom does the Renewable Volume Obligation apply?
80.1107 How is the Renewable Volume Obligation calculated?
* * * * *


Sec.  80.1104  What are the implementation dates for the Renewable Fuel 
Standard Program?

    The RFS standards and other requirements of Sec.  80.1101 and all 
sections following are effective beginning on September 1, 2007.


Sec.  80.1105  What is the Renewable Fuel Standard?

    (a) The annual value of the renewable fuel standard for 2007 shall 
be 4.02 percent.
    (b) Beginning with the 2008 compliance period, EPA will calculate 
the value of the annual standard and publish this value in the Federal 
Register by November 30 of the year preceding the compliance period.
    (c) EPA will base the calculation of the standard on information 
provided by the Energy Information Administration regarding projected 
gasoline volumes and projected volumes of renewable fuel expected to be 
used in gasoline blending for the upcoming year.
    (d) EPA will calculate the annual renewable fuel standard using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR01MY07.059

Where:

RFStdi = Renewable Fuel Standard, in year i, in percent.
RFVi = Nationwide annual volume of renewable fuels 
required by section 211(o)(2)(B) of the Act (42 U.S.C. 7545), for 
year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48 
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that 
is projected to be used in the 48 contiguous states, in year i, in 
gallons.
GSi = Amount of gasoline projected to be used in 
noncontiguous states or territories (if the state or territory opts-
in), in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that 
is projected to be used in noncontiguous states or territories (if 
the

[[Page 23994]]

state or territory opts-in), in year i, in gallons.
GEi = Amount of gasoline projected to be produced by 
exempt small refineries and small refiners, in year i, in gallons 
(through 2010 only, except to the extent that a small refinery 
exemption is extended pursuant to Sec.  80.1141(e)).
Celli = Beginning in 2013, the amount of renewable fuel 
that is required to come from cellulosic sources, in year i, in 
gallons.

    (e) Beginning with the 2013 compliance period, EPA will calculate 
the value of the annual cellulosic standard and publish this value in 
the Federal Register by November 30 of the year preceding the 
compliance period.
    (f) EPA will calculate the annual cellulosic standard using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR01MY07.060

Where:

RFCelli = Renewable Fuel Cellulosic Standard in year i, 
in percent.
Gi = Amount of gasoline projected to be used in the 48 
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that 
is projected to be used in the 48 contiguous states, in year i, in 
gallons.
GSi = Amount of gasoline projected to be used in 
noncontiguous states or territories (if the state or territory opts-
in), in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that 
is projected to be used in noncontiguous states or territories (if 
the state or territory opts-in), in year i, in gallons.
Celli = Amount of renewable fuel that is required to come 
from cellulosic sources, in year i, in gallons.


Sec.  80.1106  To whom does the Renewable Volume Obligation apply?

    (a) (1) An obligated party is a refiner that produces gasoline 
within the 48 contiguous states, or an importer that imports gasoline 
into the 48 contiguous states. A party that simply adds renewable fuel 
to gasoline, as defined in Sec.  80.1107(c), is not an obligated party.
    (2) If the Administrator approves a petition of Alaska, Hawaii, or 
a United States territory to opt-in to the renewable fuel program under 
the provisions in Sec.  80.1143, then ``obligated party'' shall also 
include any refiner that produces gasoline within that state or 
territory, or any importer that imports gasoline into that state or 
territory.
    (3) For the purposes of this section, ``gasoline'' refers to any 
and all of the products specified at Sec.  80.1107(c).
    (b) For each compliance period starting with 2007, any obligated 
party is required to demonstrate, pursuant to Sec.  80.1127, that it 
has satisfied the Renewable Volume Obligation for that compliance 
period, as specified in Sec.  80.1107(a).
    (c) An obligated party may comply with the requirements of 
paragraph (b) of this section for all of its refineries in the 
aggregate, or for each refinery individually.
    (d) An obligated party must comply with the requirements of 
paragraph (b) of this section for all of its imported gasoline in the 
aggregate.
    (e) An obligated party that is both a refiner and importer must 
comply with the requirements of paragraph (b) of this section for its 
imported gasoline separately from gasoline produced by its refinery or 
refineries.
    (f) Where a refinery or importer is jointly owned by two or more 
parties, the requirements of paragraph (b) of this section may be met 
by one of the joint owners for all of the gasoline produced at the 
refinery, or all of the imported gasoline, in the aggregate, or each 
party may meet the requirements of paragraph (b) of this section for 
the portion of the gasoline that it owns, as long as all of the 
gasoline produced at the refinery, or all of the imported gasoline, is 
accounted for in determining the renewable fuels obligation under Sec.  
80.1107.
    (g) The requirements in paragraph (b) of this section apply to the 
following compliance periods:
    (1) For 2007, the compliance period is September 1 through December 
31.
    (2) Beginning in 2008, and every year thereafter, the compliance 
period is January 1 through December 31.


Sec.  80.1107  How is the Renewable Volume Obligation calculated?

    (a) The Renewable Volume Obligation for an obligated party is 
determined according to the following formula:

RVOi = (RFStdi * GVi) + 
Di-1

Where:

RVOi = The Renewable Volume Obligation for an obligated 
party for calendar year i, in gallons of renewable fuel.
RFStdi = The renewable fuel standard for calendar year i, 
determined by EPA pursuant to Sec.  80.1105, in percent.
GVi = The non-renewable gasoline volume, determined in 
accordance with paragraphs (b), (c), and (d) of this section, which 
is produced or imported by the obligated party in calendar year i, 
in gallons.
Di-1 = Renewable fuel deficit carryover from the previous 
year, per Sec.  80.1127(b), in gallons.

    (b) The non-renewable gasoline volume for a refiner, blender, or 
importer for a given year, GVi, specified in paragraph (a) 
of this section is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR01MY07.061

Where:

x = Individual batch of gasoline produced or imported in calendar 
year i.
n = Total number of batches of gasoline produced or imported in 
calendar year i.
Gx = Volume of batch x of gasoline produced or imported, 
in gallons.
y = Individual batch of renewable fuel blended into gasoline in 
calendar year i.
m = Total number of batches of renewable fuel blended into gasoline 
in calendar year i.
RBy = Volume of batch y of renewable fuel blended into 
gasoline, in gallons.

    (c) All of the following products that are produced or imported 
during a compliance period, collectively called ``gasoline'' for the 
purposes of this section (unless otherwise specified), are to be 
included in the volume used to calculate a party's renewable volume 
obligation under paragraph (a) of this section, except as provided in 
paragraph (d) of this section:
    (1) Reformulated gasoline, whether or not renewable fuel is later 
added to it.
    (2) Conventional gasoline, whether or not renewable fuel is later 
added to it.
    (3) Reformulated gasoline blendstock that becomes finished 
reformulated gasoline upon the addition of oxygenate (``RBOB'').
    (4) Conventional gasoline blendstock that becomes finished 
conventional gasoline upon the addition of oxygenate (``CBOB'').
    (5) Blendstock (including butane and gasoline treated as blendstock 
(``GTAB'')) that has been combined with other blendstock and/or 
finished gasoline to produce gasoline.
    (6) Any gasoline, or any unfinished gasoline that becomes finished 
gasoline upon the addition of oxygenate, that is produced or imported 
to comply with a state or local fuels program.
    (d) The following products are not included in the volume of 
gasoline produced or imported used to calculate a party's renewable 
volume obligation under paragraph (a) of this section:
    (1) Any renewable fuel as defined in Sec.  80.1101(d).
    (2) Blendstock that has not been combined with other blendstock or 
finished gasoline to produce gasoline.
    (3) Gasoline produced or imported for use in Alaska, Hawaii, the 
Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American 
Samoa, and the Commonwealth of the Northern Marianas, unless the area 
has opted into the RFS program under Sec.  80.1143.
    (4) Gasoline produced by a small refinery that has an exemption 
under Sec.  80.1141 or an approved small refiner

[[Page 23995]]

that has an exemption under Sec.  80.1142 until January 1, 2011 (or 
later, for small refineries, if their exemption is extended pursuant to 
Sec.  80.1141(e)).
    (5) Gasoline exported for use outside the 48 United States, and 
gasoline exported for use outside Alaska, Hawaii, the Commonwealth of 
Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the 
Commonwealth of the Northern Marianas, if the area has opted into the 
RFS program under Sec.  80.1143.
    (6) For blenders, the volume of finished gasoline, RBOB, or CBOB to 
which a blender adds blendstocks.
    (7) The gasoline portion of transmix produced by a transmix 
processor, or the transmix blended into gasoline by a transmix blender, 
under 40 CFR 80.84.


Sec. Sec.  80.1108 through 80.1114  [Reserved]

0
6. Sections 80.1108 through 80.1114 are reserved.


0
7. Section 80.1115 is added to read as follows:


Sec.  80.1115  How are equivalence values assigned to renewable fuel?

    (a)(1) Each gallon of a renewable fuel shall be assigned an 
equivalence value by the producer or importer pursuant to paragraph (b) 
or (c) of this section.
    (2) The equivalence value is a number that is used to determine how 
many gallon-RINs can be generated for a batch of renewable fuel 
according to Sec.  80.1126.
    (b) Equivalence values shall be assigned for certain renewable 
fuels as follows:
    (1) Cellulosic biomass ethanol and waste derived ethanol produced 
on or before December 31, 2012 which is denatured shall have an 
equivalence value of 2.5.
    (2) Ethanol other than cellulosic biomass ethanol or waste-derived 
ethanol which is denatured shall have an equivalence value of 1.0.
    (3) Biodiesel (mono-alkyl ester) shall have an equivalence value of 
1.5.
    (4) Butanol shall have an equivalence value of 1.3.
    (5) Non-ester renewable diesel, including that produced from 
coprocessing a renewable crude with fossil fuels in a hydrotreater, 
shall have an equivalence value of 1.7.
    (6) All other renewable crude-based renewable fuels shall have an 
equivalence value of 1.0.
    (c)(1) For renewable fuels not listed in paragraph (b) of this 
section, a producer or importer shall submit an application to the 
Agency for an equivalence value following the provisions of paragraph 
(d) of this section.
    (2) A producer or importer may also submit an application for an 
alternative equivalence value pursuant to paragraph (d) of this section 
if the renewable fuel is listed in paragraph (b) of this section, but 
the producer or importer has reason to believe that a different 
equivalence value than that listed in paragraph (b) of this section is 
warranted.
    (d) Determination of equivalence values. (1) Except as provided in 
paragraph (d)(4) of this section, the equivalence value for renewable 
fuels described in paragraph (c) of this section shall be calculated 
using the following formula:

EV = (R / 0.931) * (EC / 77,550)

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).

    (2) The application for an equivalence value shall include a 
technical justification that includes a description of the renewable 
fuel, feedstock(s) used to make it, and the production process.
    (3) The Agency will review the technical justification and assign 
an appropriate Equivalence Value to the renewable fuel based on the 
procedure in this paragraph (d).
    (4) For biogas, the Equivalence Value is 1.0, and 77,550 Btu of 
biogas is equivalent to 1 gallon of renewable fuel.


Sec. Sec.  80.1116 through 80.1124  [Reserved]

0
8. Sections 80.1116 through 80.1124 are reserved.

0
9. Sections 80.1125 through 80.1132 are added to read as follows:

Subpart K--Renewable Fuel Standard

* * * * *
Sec.
80.1125 Renewable Identification Numbers (RINs).
80.1126 How are RINs generated and assigned to batches of renewable 
fuel by renewable fuel producers or importers?
80.1127 How are RINs used to demonstrate compliance?
80.1128 General requirements for RIN distribution.
80.1129 Requirements for separating RINs from volumes of renewable 
fuel.
80.1130 Requirements for exporters of renewable fuels.
80.1131 Treatment of invalid RINs.
80.1132 Reported spillage of renewable fuel.
* * * * *


Sec.  80.1125  Renewable Identification Numbers (RINs).

    Each RIN is a 38 character numeric code of the following form:
    KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
    (a) K is a number identifying the type of RIN as follows:
    (1) K has the value of 1 when the RIN is assigned to a volume of 
renewable fuel pursuant to Sec. Sec.  80.1126(e) and 80.1128(a).
    (2) K has the value of 2 when the RIN has been separated from a 
volume of renewable fuel pursuant to Sec.  80.1126(e)(4) or Sec.  
80.1129.
    (b) YYYY is the calendar year in which the batch of renewable fuel 
was produced or imported. YYYY also represents the year in which the 
RIN was originally generated.
    (c) CCCC is the registration number assigned according to Sec.  
80.1150 to the producer or importer of the batch of renewable fuel.
    (d) FFFFF is the registration number assigned according to Sec.  
80.1150 to the facility at which the batch of renewable fuel was 
produced or imported.
    (e) BBBBB is a serial number assigned to the batch which is chosen 
by the producer or importer of the batch such that no two batches have 
the same value in a given calendar year.
    (f) RR is a number representing the equivalence value of the 
renewable fuel as specified in Sec.  80.1115 and multiplied by 10 to 
produce the value for RR.
    (g) D is a number identifying the type of renewable fuel, as 
follows:
    (1) D has the value of 1 if the renewable fuel can be categorized 
as cellulosic biomass ethanol as defined in Sec.  80.1101(a).
    (2) D has the value of 2 if the renewable fuel cannot be 
categorized as cellulosic biomass ethanol as defined in Sec.  
80.1101(a).
    (h) SSSSSSSS is a number representing the first gallon-RIN 
associated with a batch of renewable fuel.
    (i) EEEEEEEE is a number representing the last gallon-RIN 
associated with a batch of renewable fuel. EEEEEEEE will be identical 
to SSSSSSSS if the batch-RIN represents a single gallon-RIN. Assign the 
value of EEEEEEEE as described in Sec.  80.1126.


Sec.  80.1126  How are RINs generated and assigned to batches of 
renewable fuel by renewable fuel producers or importers?

    (a) Regional applicability. (1) Except as provided in paragraph (b) 
of this section, a RIN must be assigned by a renewable fuel producer or 
importer to every batch of renewable fuel produced by a facility 
located in the contiguous 48 states of the United States, or imported 
into the contiguous 48 states.
    (2) If the Administrator approves a petition of Alaska, Hawaii, or 
a United

[[Page 23996]]

States territory to opt-in to the renewable fuel program under the 
provisions in Sec.  80.1143, then the requirements of paragraph (a)(1) 
of this section shall also apply to renewable fuel produced or imported 
into that state or territory beginning in the next calendar year.
    (b) Volume threshold. Renewable fuel producers located within the 
United States that produce less than 10,000 gallons of renewable fuel 
each year, and importers that import less than 10,000 gallons of 
renewable fuel each year, are not required to generate and assign RINs 
to batches of renewable fuel. Such producers and importers are also 
exempt from the registration, reporting, and recordkeeping requirements 
of Sec. Sec.  80.1150-80.1152. However, for such producers and 
importers that voluntarily generate and assign RINs, all the 
requirements of this subpart apply.
    (c) Definition of batch. For the purposes of this section and Sec.  
80.1125, a ``batch of renewable fuel'' is a volume of renewable fuel 
that has been assigned a unique RIN code BBBBB within a calendar year 
by the producer or importer of the renewable fuel in accordance with 
the provisions of this section and Sec.  80.1125.
    (1) The number of gallon-RINs generated for a batch of renewable 
fuel may not exceed 99,999,999.
    (2) A batch of renewable fuel cannot represent renewable fuel 
produced or imported in excess of one calendar month.
    (d) Generation of RINs. (1) Except as provided in paragraph (b) of 
this section, the producer or importer of a batch of renewable fuel 
must generate RINs for that batch, including any renewable fuel 
contained in imported gasoline.
    (2) A producer or importer of renewable fuel may generate RINs for 
volumes of renewable fuel that it owns on September 1, 2007.
    (3) A party generating a RIN shall specify the appropriate 
numerical values for each component of the RIN in accordance with the 
provisions of Sec.  80.1125 and this paragraph (d).
    (4) Except as provided in paragraph (d)(6) of this section, the 
number of gallon-RINs that shall be generated for a given batch of 
renewable fuel shall be equal to a volume calculated according to the 
following formula:

VRIN = EV * Vs

Where:

VRIN = RIN volume, in gallons, for use determining the 
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec.  80.1115.
Vs = Standardized volume of the batch of renewable fuel 
at 60 [deg]F, in gallons, calculated in accordance with paragraph 
(d)(7) of this section.

    (5) Multiple gallon-RINs generated to represent a given volume of 
renewable fuel can be represented by a single batch-RIN through the 
appropriate designation of the RIN volume codes SSSSSSSS and EEEEEEEE.
    (i) The value of SSSSSSSS in the batch-RIN shall be 00000001 to 
represent the first gallon-RIN associated with the volume of renewable 
fuel.
    (ii) The value of EEEEEEEE in the batch-RIN shall represent the 
last gallon-RIN associated with the volume of renewable fuel, based on 
the RIN volume determined pursuant to paragraph (d)(4) of this section.
    (6) (i) For renewable crude-based renewable fuels produced in a 
facility or unit that coprocesses renewable crudes and fossil fuels, 
the number of gallon-RINs that shall be generated for a given batch of 
renewable fuel shall be equal to the gallons of renewable crude used 
rather than the gallons of renewable fuel produced.
    (ii) Parties that produce renewable crude-based renewable fuels in 
a facility or unit that coprocesses renewable crudes and fossil fuels 
may submit a petition to the Agency requesting the use of volumes of 
renewable fuel produced as the basis for the number of gallon-RINs, 
pursuant to paragraph (d)(4) of this section.
    (7) Standardization of volumes. In determining the standardized 
volume of a batch of renewable fuel for purposes of generating RINs 
under this paragraph (d), the batch volumes shall be adjusted to a 
standard temperature of 60 [deg]F.
    (i) For ethanol, the following formula shall be used:

Vs,e = Va,e * (-0.0006301 * T + 1.0378)

Where:

Vs,e = Standardized volume of ethanol at 60 [deg]F, in 
gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.

    (ii) For biodiesel (mono alkyl esters), the following formula shall 
be used:

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

Where:

Vs,b = Standardized volume of biodiesel at 60 [deg]F, in 
gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.

    (iii) For other renewable fuels, an appropriate formula commonly 
accepted by the industry shall be used to standardize the actual volume 
to 60 [deg]F. Formulas used must be reported to the Agency, and may be 
reviewed for appropriateness.
    (8) (i) A party is prohibited from generating RINs for a volume of 
renewable fuel that it produces if:
    (A) The renewable fuel has been produced from a chemical conversion 
process that uses another renewable fuel as a feedstock; and
    (B) The renewable fuel used as a feedstock was produced by another 
party.
    (ii) Any RINs that the party acquired with renewable fuel used as a 
feedstock shall be assigned to the new renewable fuel that was made 
with that feedstock.
    (e) Assignment of RINs to batches. (1) Except as provided in 
paragraph (e)(4) of this section, the producer or importer of renewable 
fuel must assign all RINs generated to volumes of renewable fuel.
    (2) A RIN is assigned to a volume of renewable fuel when ownership 
of the RIN is transferred along with the transfer of ownership of the 
volume of renewable fuel, pursuant to Sec.  80.1128(a).
    (3) All assigned RINs shall have a K code value of 1.
    (4) RINs not assigned to batches. (i) If a party produces or 
imports a batch of cellulosic biomass ethanol or waste-derived ethanol 
having an equivalence value of 2.5, that party must assign at least one 
gallon-RIN to each gallon of cellulosic biomass ethanol or waste-
derived ethanol, representing the first 1.0 portion of the Equivalence 
Value.
    (ii) Any remaining gallon-RINs generated for the cellulosic biomass 
ethanol or waste-derived ethanol which represent the remaining 1.5 
portion of the Equivalence Value may remain unassigned.
    (iii) The producer or importer of cellulosic biomass ethanol or 
waste-derived ethanol shall designate the K code as 2 for all 
unassigned RINs.


Sec.  80.1127  How are RINs used to demonstrate compliance?

    (a) Renewable volume obligations. (1) Except as specified in 
paragraph (b) of this section, each party that is obligated to meet the 
Renewable Volume Obligation under Sec.  80.1107, or each party that is 
an exporter of renewable fuels that is obligated to meet a Renewable 
Volume Obligation under Sec.  80.1130, must demonstrate pursuant to 
Sec.  80.1152(a)(1) that it has taken ownership of sufficient RINs to 
satisfy the following equation:

(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i 
+ 
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = RVOi

Where:

(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i
 = Sum of all owned gallon-RINs that were generated in year i and 
are being applied towards the RVOi, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = Sum of all owned gallon-RINs that were generated in year i-1 and 
are being applied towards the RVOi, in gallons.

[[Page 23997]]

RVOi = The Renewable Volume Obligation for the obligated 
party or renewable fuel exporter for calendar year i, in gallons, 
pursuant to Sec.  80.1107 or Sec.  80.1130.

    (2) For compliance for calendar years 2008 and later, the value of 
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 may not exceed a value determined by the following inequality:

(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 <= 0.20 x RVOi

    (3) RINs may only be used to demonstrate compliance with the RVO 
for the calendar year in which they were generated or the following 
calendar year. RINs used to demonstrate compliance in one year cannot 
be used to demonstrate compliance in any other year.
    (4) A party may only use a RIN for purposes of meeting the 
requirements of paragraphs (a)(1) and (a)(2) of this section if that 
RIN is an unassigned RIN with a K code of 2 obtained in accordance with 
Sec. Sec.  80.1126(e)(4), 80.1128, and 80.1129.
    (5) The number of gallon-RINs associated with a given batch-RIN 
that can be used for compliance with the RVO shall be calculated from 
the following formula:

RINNUM = EEEEEEEE-SSSSSSSS + 1

Where:

RINNUM = Number of gallon-RINs associated with a batch-RIN, where 
each gallon-RIN represents one gallon of renewable fuel for 
compliance purposes.
EEEEEEEE = Batch-RIN component identifying the last gallon-RIN 
associated with the batch-RIN.
SSSSSSSS = Batch-RIN component identifying the first gallon-RIN 
associated with the batch-RIN.

    (b) Deficit carryovers. (1) An obligated party or an exporter of 
renewable fuel that fails to meet the requirements of paragraphs (a)(1) 
or (a)(2) of this section for calendar year i is permitted to carry a 
deficit into year i+1 under the following conditions:
    (i) The party did not carry a deficit into calendar year i from 
calendar year i-1.
    (ii) The party subsequently meets the requirements of paragraph 
(a)(1) of this section for calendar year i+1 and carries no deficit 
into year i+2.
    (2) A deficit is calculated according to the following formula:

Di RVOi-1 
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i+1
 (<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1


Where:

Di = The deficit, in gallons, generated in calendar year 
i that must be carried over to year i+1 if allowed to do so pursuant 
to paragraph (b)(1)(i) of this section.
RVOi = The Renewable Volume Obligation for the obligated 
party or renewable fuel exporter for calendar year i, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = Sum of all acquired gallon-RINs that were generated in year i and 
are being applied towards the RVOi, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = Sum of all acquired gallon-RINs that were generated in year i-1 
and are being applied towards the RVOi, in gallons.


Sec.  80.1128  General requirements for RIN distribution.

    (a) RINs assigned to volumes of renewable fuel. (1) Assigned RIN, 
for the purposes of this subpart, means a RIN assigned to a volume of 
renewable fuel pursuant to Sec.  80.1126(e) with a K code of 1.
    (2) Except as provided in Sec.  80.1126(e)(4) and Sec.  80.1129, no 
party can separate a RIN that has been assigned to a batch pursuant to 
Sec.  80.1126(e).
    (3) An assigned RIN cannot be transferred to another party without 
simultaneously transferring a volume of renewable fuel to that same 
party.
    (4) No more than 2.5 assigned gallon-RINs with a K code of 1 can be 
transferred to another party with every gallon of renewable fuel 
transferred to that same party.
    (5) (i) On each of the dates listed in paragraph (a)(5)(v) of this 
section in any calendar year, the following equation must be satisfied 
for assigned RINs and volumes of renewable fuel owned by a party:

<3-ln [><5-ln )>{<3-ln ]>(RIN)D <= 
<3-ln [><5-ln )>{<3-ln ]>(Vsi 
xEVi)D

Where:

D = Applicable date.
<3-ln [><5-ln )>{<3-ln ]>(RIN)D 
= Sum of all assigned gallon-RINs with a K code of 1 that are owned 
on date D.
(Vsi)D = Volume i of renewable fuel owned on 
date D, standardized to 60 [deg]F, in gallons.
EVi = Equivalence value representing volume i.
<3-ln [><5-ln )>{<3-ln ]>(Vsix 
EVi)D = Sum of all volumes of renewable fuel 
owned on date D, multiplied by their respective equivalence values.

    (ii) The equivalence value EVi for use in the equation 
in paragraph (a)(5)(i) of this section for any volume of ethanol shall 
be 2.5.
    (iii) If the equivalence value for a volume of renewable fuel i can 
be determined pursuant to Sec.  80.1115 based on its composition, then 
the appropriate equivalence value shall be used for EVi.
    (iv) If the equivalence value for a volume of renewable fuel cannot 
be determined based on its composition, the value of EVi 
shall be 1.0.
    (v) The applicable dates are March 31, June 30, September 30, and 
December 31. For 2007 only, the applicable dates are September 30, and 
December 31.
    (6) Producers and importers of renewable fuel. (i) Except as 
provided in paragraph (a)(6)(ii) of this section, a producer or 
importer of renewable fuel must transfer ownership of a number of 
gallon-RINs with a K code of 1 whenever it transfers ownership of a 
volume of renewable fuel such that the ratio of gallon-RINs to gallons 
is equal to the equivalence value for the renewable fuel.

<3-ln [><5-ln )>{<3-ln ]>(RIN) / 
Vs = EV

Where:

<3-ln [><5-ln )>{<3-ln ]>(RIN) = Sum of 
all gallon-RINs with a K code of 1 which are transferred along with 
volume Vs.
Vs = A volume of renewable fuel transferred, standardized 
to 60 [deg]F, in gallons.
EV = Equivalence value assigned to the renewable fuel being 
transferred.

    (ii) A producer or importer of renewable fuel can transfer 
ownership of a volume of renewable fuel without simultaneously 
transferring ownership of gallon-RINs having a K code of 1 if it can 
demonstrate one of the following:
    (A) It is a small volume producer exempt from the requirement to 
generate RINs pursuant to Sec.  80.1126(b); or
    (B) The producer or importer received an equivalent volume of 
renewable fuel from another party without accompanying RINs.
    (C) The producer or importer has generated RINs for cellulosic 
biomass ethanol or waste-derived ethanol having an equivalence value of 
2.5, and has chosen to specify as unassigned a number of gallon-RINs 
pursuant to Sec.  80.1126(e)(4).
    (7) Any transfer of ownership of assigned RINs must be documented 
on product transfer documents generated pursuant to Sec.  80.1153.
    (i) The RIN must be recorded on the product transfer document used 
to transfer ownership of the RIN and the volume to another party; or
    (ii) The RIN must be recorded on a separate product transfer 
document transferred to the same party on the same day as the product 
transfer document used to transfer ownership of the volume of renewable 
fuel.
    (b) RINs not assigned to volumes of renewable fuel. (1) Unassigned 
RIN, for the purposes of this subpart, means a RIN with a K code of 2 
that has been separated from a volume of renewable fuel pursuant to 
Sec.  80.1126(e)(4) or Sec.  80.1129.
    (2) Any party that has registered pursuant to Sec.  80.1150 can 
hold title to an unassigned RIN.
    (3) Unassigned RINs can be transferred from one party to another 
any number of times.
    (4) An unassigned batch-RIN can be divided by its holder into 
multiple batch-RINs, each representing a smaller number of gallon-RINs, 
if all of the following conditions are met:

[[Page 23998]]

    (i) All RIN components other than SSSSSSSS and EEEEEEEE are 
identical for the original parent and newly formed daughter RINs.
    (ii) The sum of the gallon-RINs associated with the multiple 
daughter batch-RINs is equal to the gallon-RINs associated with the 
parent batch-RIN.


Sec.  80.1129  Requirements for separating RINs from volumes of 
renewable fuel.

    (a)(1) Separation of a RIN from a volume of renewable fuel means 
termination of the assignment of the RIN to a volume of renewable fuel.
    (2) RINs that have been separated from volumes of renewable fuel 
become unassigned RINs subject to the provisions of Sec.  80.1128(b).
    (b) A RIN that is assigned to a volume of renewable fuel is 
separated from that volume only under one of the following conditions:
    (1) Except as provided in paragraph (b)(6) of this section, a party 
that is an obligated party according to Sec.  80.1106 must separate any 
RINs that have been assigned to a volume of renewable fuel if they own 
that volume.
    (2) Except as provided in paragraph (b)(5) of this section, any 
party that owns a volume of renewable fuel must separate any RINs that 
have been assigned to that volume once the volume is blended with 
gasoline or diesel to produce a motor vehicle fuel.
    (3) Any party that exports a volume of renewable fuel must separate 
any RINs that have been assigned to the exported volume.
    (4) Any renewable fuel producer or importer that produces or 
imports a volume of renewable fuel shall have the right to separate any 
RINs that have been assigned to that volume if the producer or importer 
designates the renewable fuel as motor vehicle fuel and the renewable 
fuel is used as motor vehicle fuel.
    (5) RINs assigned to a volume of biodiesel (mono-alkyl ester) can 
only be separated from that volume pursuant to paragraph (b)(2) of this 
section if such biodiesel is blended into diesel fuel at a 
concentration of 80 volume percent biodiesel (mono-alkyl ester) or 
less.
    (i) This paragraph (b)(5) shall not apply to obligated parties or 
exporters of renewable fuel.
    (ii) This paragraph (b)(5) shall not apply to renewable fuel 
producers meeting the requirements of paragraph (b)(4) of this section.
    (6) For RINs that an obligated party generates, the obligated party 
can only separate such RINs from volumes of renewable fuel if the 
number of gallon-RINs separated is less than or equal to its annual 
RVO.
    (7) A producer or importer of cellulosic biomass ethanol or waste-
derived ethanol can separate a portion of the RINs that it generates 
pursuant to Sec.  80.1126(e)(4).
    (c) The party responsible for separating a RIN from a volume of 
renewable fuel shall change the K code in the RIN from a value of 1 to 
a value of 2 prior to transferring the RIN to any other party.
    (d) (1) Upon and after separation from a renewable fuel volume, a 
RIN shall not appear on documentation that is either:
    (i) Used to identify title to the volume of renewable fuel; or
    (ii) Transferred with the volume of renewable fuel.
    (2) Upon and after separation of a RIN from its associated volume, 
product transfer documents used to transfer ownership of the volume 
must continue to meet the requirements of Sec.  80.1153(a)(5)(iii).
    (e) Any obligated party that uses a renewable fuel in a boiler or 
heater must retire any RINs associated with that volume of renewable 
fuel and report the retired RINs in the applicable reports under Sec.  
80.1152.


Sec.  80.1130  Requirements for exporters of renewable fuels.

    (a) Any party that owns any amount of renewable fuel (in its neat 
form or blended with gasoline or diesel) that is exported from the 
region described in Sec.  80.1126(a) shall acquire sufficient RINs to 
offset a Renewable Volume Obligation representing the exported 
renewable fuel.
    (b) Renewable Volume Obligations. An exporter of renewable fuel 
shall determine its Renewable Volume Obligation from the volumes of the 
renewable fuel exported.
    (1) A renewable fuel exporter's total Renewable Volume Obligation 
shall be calculated according to the following formula:

RVOi = [Sgr](VOLk * EVk)i + 
Di-1

Where:

RVOi = The Renewable Volume Obligation for the exporter 
for calendar year i, in gallons of renewable fuel.
k = A discrete volume of renewable fuel.
VOLk = The standardized volume of discrete volume k of 
exported renewable fuel, in gallons, calculated in accordance with 
Sec.  80.1126(d)(7).
EVk = The equivalence value associated with discrete 
volume k.
[Sgr] = Sum involving all volumes of renewable fuel exported.
    Di-1 = Renewable fuel deficit carryover from the 
previous year, in gallons.

    (2)(i) If the equivalence value for a volume of renewable fuel can 
be determined pursuant to Sec.  80.1115 based on its composition, then 
the appropriate equivalence value shall be used in the calculation of 
the exporter's Renewable Volume Obligation.
    (ii) If the equivalence value for a volume of renewable fuel cannot 
be determined, the value of EVk shall be 1.0.
    (c) Each exporter of renewable fuel must demonstrate compliance 
with its RVO using RINs it has acquired pursuant to Sec.  80.1127.


Sec.  80.1131  Treatment of invalid RINs.

    (a) Invalid RINs. An invalid RIN is a RIN that is any of the 
following:
    (1) Is a duplicate of a valid RIN.
    (2) Was based on volumes that have not been standardized to 60 
[deg]F.
    (3) Has expired.
    (4) Was based on an incorrect equivalence value.
    (5) Is deemed invalid under Sec.  80.1167(g).
    (6) Does not represent renewable fuel as it is defined in Sec.  
80.1101.
    (7) Was otherwise improperly generated.
    (b) In the case of RINs that are invalid, the following provisions 
apply:
    (1) Invalid RINs cannot be used to achieve compliance with the 
Renewable Volume Obligation of an obligated party or exporter, 
regardless of the party's good faith belief that the RINs were valid at 
the time they were acquired.
    (2) Upon determination by any party that RINs owned are invalid, 
the party must adjust their records, reports, and compliance 
calculations as necessary to reflect the deletion of the invalid RINs.
    (3) Any valid RINs remaining after deleting invalid RINs must first 
be applied to correct the transfer of invalid RINs to another party 
before applying the valid RINs to meet the party's Renewable Volume 
Obligation at the end of the compliance year.
    (4) In the event that the same RIN is transferred to two or more 
parties, all such RINs will be deemed to be invalid, unless EPA in its 
sole discretion determines that some portion of these RINs is valid.


Sec.  80.1132  Reported spillage of renewable fuel.

    (a) A reported spillage under paragraph (d) of this section means a 
spillage of renewable fuel associated with a requirement by a federal, 
state or local authority to report the spillage.
    (b) Except as provided in paragraph (c) of this section, in the 
event of a reported spillage of any volume of renewable fuel, the owner 
of the renewable fuel must retire a number of gallon-RINs corresponding 
to the volume of spilled renewable fuel multiplied by its equivalence 
value.


[[Continued on page 23999]]


From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 23999-24014]] Regulation of Fuels and Fuel Additives: Renewable Fuel Standard 
Program

[[Continued from page 23998]]

[[Page 23999]]

    (1) If the equivalence value for the spilled volume may be 
determined pursuant to Sec.  80.1115 based on its composition, then the 
appropriate equivalence value shall be used.
    (2) If the equivalence value for a spilled volume of renewable fuel 
cannot be determined, the equivalence value shall be 1.0.
    (c) If the owner of a volume of renewable fuel that is spilled and 
reported establishes that no RINs were generated to represent the 
volume, then no gallon-RINs shall be retired.
    (d) A RIN that is retired under paragraph (b) of this section:
    (1) Must be reported as a retired RIN in the applicable reports 
under Sec.  80.1152.
    (2) May not be transferred to another party or used by any 
obligated party to demonstrate compliance with the party's Renewable 
Volume Obligation.


Sec. Sec.  80.1133 through 80.1140  [Reserved]

0
10. Sections 80.1133 through 80.1140 are reserved.


0
11. Sections 80.1141 through 80.1143 are added to read as follows:


Sec.  80.1141  Small refinery exemption.

    (a)(1) Gasoline produced at a refinery by a refiner, or foreign 
refiner (as defined at Sec.  80.1165(a)), is exempt from the renewable 
fuel standards of Sec.  80.1105 if that refinery meets the definition 
of a small refinery under Sec.  80.1101(g) for calendar year 20460.
    (2) This exemption shall apply through December 31, 2010, unless a 
refiner chooses to waive this exemption (as described in paragraph (f) 
of this section), or the exemption is extended (as described in 
paragraph (e) of this section).
    (3) For the purposes of this section, the term ``refiner'' shall 
include foreign refiners.
    (b)(1) The small refinery exemption is effective immediately, 
except as specified in paragraph (b)(4) of this section.
    (2) A refiner owning a small refinery must submit a verification 
letter to EPA containing all of the following information:
    (i) The annual average aggregate daily crude oil throughput for the 
period January 1, 2004, through December 31, 2004 (as determined by 
dividing the aggregate throughput for the calendar year by the number 
365).
    (ii) A letter signed by the president, chief operating or chief 
executive officer of the company, or his/her designee, stating that the 
information contained in the letter is true to the best of his/her 
knowledge, and that the company owned the refinery as of January 1, 
2004.
    (iii) Name, address, phone number, facsimile number, and e-mail 
address of a corporate contact person.
    (3) Verification letters must be submitted by August 31, 2007, to 
one of the addresses listed in paragraph (h) of this section.
    (4) For foreign refiners the small refinery exemption shall be 
effective upon approval, by EPA, of a small refinery application. The 
application must contain all of the elements required for small 
refinery verification letters (as specified in paragraph (b)(2) of this 
section), must satisfy the provisions of Sec.  80.1165(f) through (h) 
and (o), and must be submitted by August 31, 2007 to one of the 
addresses listed in paragraph (h) of this section.
    (c) If EPA finds that a refiner provided false or inaccurate 
information regarding a refinery's crude throughput (pursuant to 
paragraph (b)(2)(i) of this section) in its small refinery verification 
letter, the exemption will be void as of the effective date of these 
regulations.
    (d) If a refiner is complying on an aggregate basis for multiple 
refineries, any such refiner may exclude from the calculation of its 
Renewable Volume Obligation (under Sec.  80.1107(a)) gasoline from any 
refinery receiving the small refinery exemption under paragraph (a) of 
this section.
    (e)(1) The exemption period in paragraph (a) of this section shall 
be extended by the Administrator for a period of not less than two 
additional years if a study by the Secretary of Energy determines that 
compliance with the requirements of this subpart would impose a 
disproportionate economic hardship on the small refinery.
    (i) A refiner may at any time petition the Administrator for an 
extension of its small refinery exemption under paragraph (a) of this 
section for the reason of disproportionate economic hardship.
    (ii) A petition for an extension of the small refinery exemption 
must specify the factors that demonstrate a disproportionate economic 
hardship and must provide a detailed discussion regarding the inability 
of the refinery to produce gasoline meeting the requirements of Sec.  
80.1105 and the date the refiner anticipates that compliance with the 
requirements can be achieved at the small refinery.
    (2) The Administrator shall act on such a petition not later than 
90 days after the date of receipt of the petition.
    (f) At any time, a refiner with an approved small refinery 
exemption under paragraph (a) of this section may waive that exemption 
upon notification to EPA.
    (1) A refiner's notice to EPA that it intends to waive its small 
refinery exemption must be received by November 1 to be effective in 
the next compliance year.
    (2) The waiver will be effective beginning on January 1 of the 
following calendar year, at which point the gasoline produced at that 
refinery will be subject to the renewable fuels standard of Sec.  
80.1105.
    (3) The waiver must be sent to EPA at one of the addresses listed 
in paragraph (h) of this section.
    (g) A refiner that acquires a refinery from either an approved 
small refiner (as defined under Sec.  80.1142(a)) or another refiner 
with an approved small refinery exemption under paragraph (a) of this 
section shall notify EPA in writing no later than 20 days following the 
acquisition.
    (h) Verification letters under paragraph (b) of this section, 
petitions for small refinery hardship extensions under paragraph (e) of 
this section, and small refinery exemption waivers under paragraph (f) 
of this section shall be sent to one of the following addresses:
    (1) For U.S. mail: U.S. EPA--Attn: RFS Program, 6406J, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460.
    (2) For overnight or courier services: U.S. EPA, Attn: RFS Program, 
6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.


Sec.  80.1142  What are the provisions for small refiners under the RFS 
program?

    (a) (1) Gasoline produced by a refiner, or foreign refiner (as 
defined at Sec.  80.1165(a)), is exempt from the renewable fuel 
standards of Sec.  80.1105 if the refiner or foreign refiner does not 
meet the definition of a small refinery under Sec.  80.1101(g) but 
meets all of the following criteria:
    (i) The refiner produced gasoline at its refineries by processing 
crude oil through refinery processing units from January 1, 2004 
through December 31, 2004.
    (ii) The refiner employed an average of no more than 1,500 people, 
based on the average number of employees for all pay periods for 
calendar year 2004 for all subsidiary companies, all parent companies, 
all subsidiaries of the parent companies, and all joint venture 
partners.
    (iii) The refiner had a corporate-average crude oil capacity less 
than or equal to 155,000 barrels per calendar day (bpcd) for 2004.
    (2) The small refiner exemption shall apply through December 31, 
2010, unless a refiner chooses to waive the

[[Page 24000]]

exemption (pursuant to paragraph (h) of this section) prior to that 
date.
    (3) For the purposes of this section, the term ``refiner'' shall 
include foreign refiners.
    (b) The small refiner exemption is effective immediately, except as 
provided in paragraph (d) of this section. Refiners who qualify for the 
small refiner exemption under paragraph (a) of this section must submit 
a verification letter (and any other relevant information) to EPA 
containing all of the following information for the refiner and for all 
subsidiary companies, all parent companies, all subsidiaries of the 
parent companies, and all joint venture partners:
    (1)(i) A listing of the name and address of each company location 
where any employee worked for the period January 1, 2004 through 
December 31, 2004.
    (ii) The average number of employees at each location based on the 
number of employees for each pay period for the period January 1, 2004 
through December 31, 2004.
    (iii) The type of business activities carried out at each location.
    (iv) For joint ventures, the total number of employees includes the 
combined employee count of all corporate entities in the venture.
    (v) For government-owned refiners, the total employee count 
includes all government employees.
    (2) The total corporate crude oil capacity of each refinery as 
reported to the Energy Information Administration (EIA) of the U.S. 
Department of Energy (DOE), for the period January 1, 2004 through 
December 31, 2004. The information submitted to EIA is presumed to be 
correct. In cases where a company disagrees with this information, the 
company may petition EPA with appropriate data to correct the record 
when the company submits its verification letter.
    (3) The verification letter must be signed by the president, chief 
operating or chief executive officer of the company, or his/her 
designee, stating that the information is true to the best of his/her 
knowledge, and that the company owned the refinery as of December 31, 
2004.
    (4) Name, address, phone number, facsimile number, and e-mail 
address of a corporate contact person.
    (c) Verification letters under paragraph (b) of this section must 
be submitted by September 1, 2007.
    (d) For foreign refiners the small refiner exemption shall be 
effective upon approval, by EPA, of a small refiner application. The 
application must contain all of the elements required for small refiner 
verification letters (as specified in paragraphs (b)(1), (b)(3), and 
(b)(4) of this section), must demonstrate compliance with the crude oil 
capacity criterion of paragraph (a)(1)(iii) of this section, must 
satisfy the provisions of Sec.  80.1165(f) through (h) and (o), and 
must be submitted by September 1, 2007 to one of the addresses listed 
in paragraph (j) of this section.
    (e) A refiner who qualifies as a small refiner under this section 
and subsequently fails to meet all of the qualifying criteria as set 
out in paragraph (a) of this section will have its small refiner 
exemption terminated effective January 1 of the next calendar year; 
however, disqualification shall not apply in the case of a merger 
between two approved small refiners.
    (f) If EPA finds that a refiner provided false or inaccurate 
information in its small refiner status verification letter under this 
subpart, the small refiner's exemption will be void as of the effective 
date of these regulations.
    (g) If a small refiner is complying on an aggregate basis for 
multiple refineries, the refiner may exempt the refineries from the 
calculation of its Renewable Volume Obligation under Sec.  80.1107.
    (h) (1) A refiner may, at any time, waive the small refiner 
exemption under paragraph (a) of this section upon notification to EPA.
    (2) A refiner's notice to EPA that it intends to waive the small 
refiner exemption must be received by November 1 in order for the 
waiver to be effective for the following calendar year. The waiver will 
be effective beginning on January 1 of the following calendar year, at 
which point the refiner will be subject to the renewable fuel standard 
of Sec.  80.1105.
    (3) The waiver must be sent to EPA at one of the addresses listed 
in paragraph (j) of this section.
    (i) Any refiner that acquires a refinery from another refiner with 
approved small refiner status under paragraph (a) of this section shall 
notify EPA in writing no later than 20 days following the acquisition.
    (j) Verification letters under paragraph (b) of this section and 
small refiner exemption waivers under paragraph (h) of this section 
shall be sent to one of the following addresses:
    (1) For U.S. Mail: U.S. EPA--Attn: RFS Program, 6406J, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460.
    (2) For overnight or courier services: U.S. EPA, Attn: RFS Program, 
6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.


Sec.  80.1143  What are the opt-in provisions for noncontiguous states 
and territories?

    (a) A noncontiguous state or United States territory may petition 
the Administrator to opt-in to the program requirements of this 
subpart.
    (b) The Administrator will approve the petition if it meets the 
provisions of paragraphs (c) and (d) of this section.
    (c) The petition must be signed by the Governor of the state or his 
authorized representative (or the equivalent official of the 
territory).
    (d)(1) A petition submitted under this section must be received by 
the Agency by November 1 for the state or territory to be included in 
the RFS program in the next calendar year.
    (2) A petition submitted under this section should be sent to 
either of the following addresses:
    (i) For U.S. Mail: U.S. EPA--Attn: RFS Program, 6406J, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460.
    (ii) For overnight or courier services: U.S. EPA, Attn: RFS 
Program, 6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.
    (e) Upon approval of the petition by the Administrator:
    (1) EPA shall calculate the standard for the following year, 
including the total gasoline volume for the State or territory in 
question.
    (2) Beginning on January 1 of the next calendar year, all gasoline 
refiners and importers in the state or territory for which a petition 
has been approved shall be obligated parties as defined in Sec.  
80.1106.
    (3) Beginning on January 1 of the next calendar year, all renewable 
fuel producers in the State or territory for which a petition has been 
approved shall, pursuant to Sec.  80.1126(a)(2), be required to 
generate RINs and assign them to batches of renewable fuel.


Sec. Sec.  80.1144 through 80.1149  [Reserved]

0
12. Sections 80.1144 through 80.1149 are reserved.


0
13. Sections 80.1150 through 80.1155 are added to read as follows:

Subpart K--Renewable Fuel Standard

* * * * *
Sec.
80.1150 What are the registration requirements under the RFS 
program?
80.1151 What are the recordkeeping requirements under the RFS 
program?
80.1152 What are the reporting requirements under the RFS program?
80.1153 What are the product transfer document (PTD) requirements 
for the RFS program?
80.1154 What are the provisions for renewable fuel producers and 
importers who produce or import less than 10,000 gallons of 
renewable fuel per year?

[[Page 24001]]

80.1155 What are the additional requirements for a producer of 
cellulosic biomass ethanol or waste derived ethanol?
* * * * *


Sec.  80.1150  What are the registration requirements under the RFS 
program?

    (a) Any obligated party described in Sec.  80.1106 and any exporter 
of renewable fuel described in Sec.  80.1130 must provide EPA with the 
information specified for registration under Sec.  80.76, if such 
information has not already been provided under the provisions of this 
part. An obligated party or an exporter of renewable fuel must receive 
EPA-issued identification numbers prior to engaging in any transaction 
involving RINs. Registration information may be submitted to EPA at any 
time after promulgation of this rule in the Federal Register.
    (b) Any importer or producer of a renewable fuel must provide EPA 
the information specified under Sec.  80.76, if such information has 
not already been provided under the provisions of this part, and must 
receive EPA-issued company and facility identification numbers prior to 
generating or assigning any RINs. Registration information may be 
submitted to EPA at any time after promulgation of this rule in the 
Federal Register.
    (c) Any party who owns or intends to own RINs, but who is not 
covered by paragraphs (a) and (b) of this section, must provide EPA the 
information specified under Sec.  80.76, if such information has not 
already been provided under the provisions of this part and must 
receive an EPA-issued company identification number prior to owning any 
RINs. Registration information may be submitted to EPA at any time 
after promulgation of this rule in the Federal Register.
    (d) Registration shall be on forms, and following policies, 
established by the Administrator.


Sec.  80.1151  What are the recordkeeping requirements under the RFS 
program?

    (a) Beginning September 1, 2007, any obligated party (as described 
at Sec.  80.1106) or exporter of renewable fuel (as described at Sec.  
80.1130) must keep all of the following records:
    (1) Product transfer documents consistent with Sec.  80.1153 and 
associated with the obligated party's activity, if any, as transferor 
or transferee of renewable fuel.
    (2) Copies of all reports submitted to EPA under Sec.  80.1152(a).
    (3) Records related to each RIN transaction, which includes all the 
following:
    (i) A list of the RINs owned, purchased, sold, retired or expired.
    (ii) The parties involved in each RIN transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RIN(s).
    (iv) Additional information related to details of the transaction 
and its terms.
    (4) Records related to the use of RINs (by facility, if applicable) 
for compliance, which includes all the following:
    (i) Methods and variables used to calculate the Renewable Volume 
Obligation pursuant to Sec.  80.1107 or Sec.  80.1130.
    (ii) List of RINs used to demonstrate compliance.
    (iii) Additional information related to details of RIN use for 
compliance.
    (b) Beginning September 1, 2007, any producer or importer of a 
renewable fuel as defined at Sec.  80.1101(d) must keep all of the 
following records:
    (1) Product transfer documents consistent with Sec.  80.1153 and 
associated with the renewable fuel producer's or importer's activity, 
if any, as transferor or transferee of renewable fuel.
    (2) Copies of all reports submitted to EPA under Sec.  80.1152(b).
    (3) Records related to the generation and assignment of RINs for 
each facility, including all of the following:
    (i) Batch volume in gallons.
    (ii) Batch number.
    (iii) RIN number as assigned under Sec.  80.1126.
    (iv) Identification of batches meeting the definition of cellulosic 
biomass ethanol.
    (v) Date of production or import.
    (vi) Results of any laboratory analysis of batch chemical 
composition or physical properties.
    (vii) Additional information related to details of RIN generation.
    (4) Records related to each RIN transaction, including all of the 
following:
    (i) A list of the RINs owned, purchased, sold, retired or expired.
    (ii) The parties involved in each transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RIN(s).
    (iv) Additional information related to details of the transaction 
and its terms.
    (5) Records related to the production or importation of any volume 
of renewable fuel that the renewable fuel producer or importer 
designates as motor vehicle fuel and the use of the fuel as motor 
vehicle fuel.
    (c) Beginning September 1, 2007, any producer of a renewable fuel 
defined at Sec.  80.1101(d) must keep verifiable records of the 
following:
    (1) The amount and type of fossil fuel and waste material-derived 
fuel used in producing on-site thermal energy dedicated to the 
production of ethanol at plants producing cellulosic biomass ethanol 
through the displacement of 90 percent or more of the fossil fuel 
normally used in the production of ethanol, as described at Sec.  
80.1101(a)(2).
    (2) The amount and type of feedstocks used in producing cellulosic 
biomass ethanol as defined in Sec.  80.1101(a)(1).
    (3) The equivalent amount of fossil fuel (based on reasonable 
estimates) associated with the use of off-site generated waste heat 
that is used in the production of ethanol at plants producing 
cellulosic biomass ethanol through the displacement of 90 percent or 
more of the fossil fuel normally used in the production of ethanol, as 
described at Sec.  80.1101(a)(2).
    (4) The plot plan and process flow diagram for plants producing 
cellulosic biomass and waste derived ethanol as defined in Sec.  
80.1101(a) and (b), respectively.
    (5) The independent third party verification required under Sec.  
80.1155 for producers of cellulosic biomass ethanol and waste derived 
ethanol.
    (d) Beginning September 1, 2007, any party, other than those 
parties covered in paragraphs (a) and (b) of this section, that owns 
RINs must keep all of the following records:
    (1) Product transfer documents consistent with Sec.  80.1153 and 
associated with the party's activity, if any, as transferor or 
transferee of renewable fuel.
    (2) Copies of all reports submitted to EPA under Sec.  80.1152(c).
    (3) Records related to each RIN transaction, including all of the 
following:
    (i) A list of the RINs owned, purchased, sold, retired or expired.
    (ii) The parties involved in each RIN transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RIN(s).
    (iv) Additional information related to details of the transaction 
and its terms.
    (e) The records required under this section and under Sec.  80.1153 
shall be kept for five years from the date they were created, except 
that records related to transactions involving RINs shall be kept for 
five years from the date of transfer.
    (f) On request by EPA, the records required under this section and 
under Sec.  80.1153 must be made available to the Administrator or the 
Administrator's authorized representative. For records that are 
electronically generated or maintained, the equipment or software

[[Page 24002]]

necessary to read the records shall be made available; or, if requested 
by EPA, electronic records shall be converted to paper documents.


Sec.  80.1152  What are the reporting requirements under the RFS 
program?

    (a) Any obligated party described in Sec.  80.1106 or exporter of 
renewable fuel described in Sec.  80.1130 must submit to EPA reports 
according to the schedule, and containing the information, that is set 
forth in this paragraph (a).
    (1) An annual compliance demonstration report for the previous 
compliance period shall be submitted every February 28, except as noted 
in paragraph (a)(1)(x) of this section, and shall include all of the 
following information:
    (i) The obligated party's name.
    (ii) The EPA company registration number.
    (iii) Whether the party is complying on a corporate (aggregate) or 
facility-by-facility basis.
    (iv) The EPA facility registration number, if complying on a 
facility-by-facility basis.
    (v) The production volume of all of the products listed in Sec.  
80.1107(c) for the reporting year.
    (vi) The renewable volume obligation (RVO), as defined in Sec.  
80.1127(a) for obligated parties and Sec.  80.1130(b) for exporters of 
renewable fuel, for the reporting year.
    (vii) Any deficit RVO carried over from the previous year.
    (viii) The total current-year gallon-RINs used for compliance.
    (ix) The total prior-years gallon-RINs used for compliance.
    (x) A list of all RINs used for compliance in the reporting year. 
For compliance demonstrations covering calendar year 2007 only, this 
list shall be reported by May 31, 2008. In all subsequent years, this 
list shall be submitted by February 28.
    (xi) Any deficit RVO carried into the subsequent year.
    (xii) Any additional information that the Administrator may 
require.
    (2) The quarterly RIN transaction reports required under paragraph 
(c)(1) of this section.
    (3) The quarterly gallon-RIN activity reports required under 
paragraph (c)(2) of this section.
    (4) Reports required under this paragraph (a) must be signed and 
certified as meeting all the applicable requirements of this subpart by 
the owner or a responsible corporate officer of the obligated party.
    (b) Any producer or importer of a renewable fuel must, beginning 
November 30, 2007, submit to EPA reports according to the schedule, and 
containing the information, that is set forth in this paragraph (b).
    (1) A quarterly RIN-generation report for each facility owned by 
the renewable fuel producer, and each importer, shall be submitted 
according to the schedule specified in paragraph (d) of this section, 
and shall include for the reporting period all of the following 
information for each batch of renewable fuel produced or imported, 
where ``batch'' means a discreet quantity of renewable fuel produced or 
imported and assigned a unique RIN:
    (i) The renewable fuel producer's or importer's name.
    (ii) The EPA company registration number.
    (iii) The EPA facility registration number.
    (iv) The applicable quarterly reporting period.
    (v) The RINs generated for each batch according to Sec.  80.1126.
    (vi) The production date of each batch.
    (vii) The type of renewable fuel of each batch, as defined in Sec.  
80.1101(d).
    (viii) Information related to the volume of denaturant and 
applicable equivalence value of each batch.
    (ix) The volume of each batch produced or imported.
    (x) Any additional information the Administrator may require.
    (2) The RIN transaction reports required under paragraph (c)(1) of 
this section.
    (3) The quarterly gallon-RIN activity report required under 
paragraph (c)(2) of this section.
    (4) Reports required under this paragraph (b) must be signed and 
certified as meeting all the applicable requirements of this subpart by 
the owner or a responsible corporate officer of the renewable fuel 
producer.
    (c) Any party, including any party specified in paragraphs (a) and 
(b) of this section, that owns RINs during a reporting period must, 
beginning November 30, 2007, submit reports to EPA according to the 
schedule, and containing the information, that is set forth in this 
paragraph (c).
    (1) A RIN transaction report for each RIN transaction shall be 
submitted by the end of the quarter in which the transaction occurred, 
according to the schedule specified in paragraph (d) of this section. 
Each report shall include all of the following:
    (i) The submitting party's name.
    (ii) The party's EPA company registration number.
    (iii) The party's facility registration number, if the report 
required under paragraph (c)(2) of this section is submitted on a 
facility-by-facility basis.
    (iv) The applicable quarterly reporting period.
    (v) Transaction type (RIN purchase, RIN sale, expired RIN, retired 
RIN).
    (vi) Transaction date.
    (vii) For a RIN purchase or sale, the trading partner's name.
    (viii) For a RIN purchase or sale, the trading partner's EPA 
company registration number. For all other transactions, the submitting 
party's EPA company registration number.
    (ix) RIN subject to the transaction.
    (x) For a retired RIN, the reason for retiring the RIN (e.g., 
reportable spill under Sec.  80.1132, import volume correction under 
Sec.  80.1166(k), renewable fuel used in boiler or heater under Sec.  
80.1129(e), enforcement obligation).
    (xi) Any additional information that the Administrator may require.
    (2) A quarterly gallon-RIN activity report shall be submitted to 
EPA according to the schedule specified in paragraph (d) of this 
section. Each report shall summarize gallon-RIN activities for the 
reporting period, separately for RINs separated from a renewable fuel 
volume and RINs assigned to a renewable fuel volume. A RIN owner with 
more than one facility may submit the report required under this 
paragraph for each of its facilities individually, or for all of its 
facilities in the aggregate. The quarterly gallon-RIN activity report 
shall include all of the following information:
    (i) The submitting party's name.
    (ii) The party's EPA company registration number.
    (iii) Whether the party is submitting the report required under 
this paragraph on a corporate (aggregate) or facility-by-facility 
basis.
    (iv) The party's EPA facility registration number, if the report 
required under this paragraph is submitted on a facility-by-facility 
basis.
    (v) Number of current-year gallon-RINs owned at the start of the 
quarter.
    (vi) Number of prior-years gallon-RINs owned at the start of the 
quarter.
    (vii) The total current-year gallon-RINs purchased.
    (viii) The total prior-years gallon-RINs purchased.
    (ix) The total current-year gallon-RINs sold.
    (x) The total prior-years gallon-RINs sold.
    (xi) The total current-year gallon-RINs retired.
    (xii) The total prior-years gallon-RINs retired.
    (xiii) The total current-year gallon-RINs expired (fourth quarter 
only).
    (xiv) The total prior-years gallon-RINs expired (fourth quarter 
only).

[[Page 24003]]

    (xv) Number of current-year gallon-RINs owned at the end of the 
quarter.
    (xvi) Number of prior-years gallon-RINs owned at the end of the 
quarter.
    (xvii) For parties reporting gallon-RIN activity under this 
paragraph for RINs assigned to a volume of renewable fuel, the volume 
of renewable fuel (in gallons) owned at the end of the quarter.
    (xviii) Any additional information that the Administrator may 
require.
    (3) All reports required under this paragraph (c) must be signed 
and certified as meeting all the applicable requirements of this 
subpart by the RIN owner or a responsible corporate officer of the RIN 
owner.
    (d) Quarterly reports shall be submitted to EPA by: May 31st for 
the first calendar quarter of January through March; August 31st for 
the second calendar quarter of April through June; November 30th for 
the third calendar quarter of July through September; and February 28th 
for the fourth calendar quarter of October through December. For 2007, 
quarterly reports shall commence on November 30, 2007.
    (e) Reports required under this section shall be submitted on forms 
and following procedures as prescribed by EPA.


Sec.  80.1153  What are the product transfer document (PTD) 
requirements for the RFS program?

    (a) Any time that a person transfers ownership of renewable fuels 
subject to this subpart, the transferor must provide to the transferee 
documents identifying the renewable fuel and any assigned RINs which 
include all of the following information as applicable:
    (1) The name and address of the transferor and transferee.
    (2) The transferor's and transferee's EPA company registration 
number.
    (3) The volume of renewable fuel that is being transferred.
    (4) The date of the transfer.
    (5) Whether any RINs are assigned to the volume, as follows:
    (i) If the assigned RINs are being transferred on the same PTD used 
to transfer ownership of the renewable fuel, then the assigned RINs 
shall be listed on the PTD.
    (ii) If the assigned RINs are being transferred on a separate PTD 
from that which is used to transfer ownership of the renewable fuel, 
then the PTD which is used to transfer ownership of the renewable fuel 
shall state the number of gallon-RINs being transferred as well as a 
unique reference to the PTD which is transferring the assigned RINs.
    (iii) If no assigned RINs are being transferred with the renewable 
fuel, the PTD which is used to transfer ownership of the renewable fuel 
shall state ``No RINs transferred''.
    (b) Except for transfers to truck carriers, retailers, or wholesale 
purchaser-consumers, product codes may be used to convey the 
information required under paragraphs (a)(1) through (a)(4) of this 
section if such codes are clearly understood by each transferee. The 
RIN number required under paragraph (a)(5) of this section must always 
appear in its entirety.


Sec.  80.1154  What are the provisions for renewable fuel producers and 
importers who produce or import less than 10,000 gallons of renewable 
fuel per year?

    (a) Renewable fuel producers located within the United States that 
produce less than 10,000 gallons of renewable fuel each year, and 
importers who import less than 10,000 gallons of renewable fuel each 
year, are not required to generate RINs or to assign RINs to batches of 
renewable fuel. Such producers and importers that do not generate and/
or assign RINs to batches of renewable fuel are also exempt from all 
the following requirements of this subpart K, except as stated in 
paragraph (b) of this section:
    (1) The registration requirements of Sec.  80.1150.
    (2) The recordkeeping requirements of Sec.  80.1151.
    (3) The reporting requirements of Sec.  80.1152.
    (b) Renewable fuel producers and importers who produce or import 
less than 10,000 gallons of renewable fuel each year and that generate 
and/or assign RINs to batches of renewable fuel are subject to the 
provisions of Sec. Sec.  80.1150 through 80.1152.


Sec.  80.1155  What are the additional requirements for a producer of 
cellulosic biomass ethanol or waste derived ethanol?

    (a) A producer of cellulosic biomass ethanol or waste derived 
ethanol (hereinafter referred to as ``ethanol producer'' under this 
section) is required to arrange for an independent third party to 
review the records required in Sec.  80.1151(c) and provide the ethanol 
producer with a written verification that the records support a claim 
that:
    (1) The ethanol producer's facility is a facility that has the 
capability of producing cellulosic biomass ethanol as defined in Sec.  
80.1101(a) or waste derived ethanol as defined in Sec.  80.1101(b); and
    (2) The ethanol producer produces cellulosic biomass ethanol as 
defined in Sec.  80.1101(a) or waste derived ethanol as defined in 
Sec.  80.1101(b).
    (b) The verifications required under paragraph (a) of this section 
must be conducted by a Professional Chemical Engineer who is based in 
the United States and is licensed by the appropriate state agency, 
unless the ethanol producer is a foreign producer subject to Sec.  
80.1166.
    (c) To be considered an independent third party under paragraph (a) 
of this section:
    (1) The third party shall not be operated by the ethanol producer 
or any subsidiary of employee of the ethanol producer.
    (2) The third party shall be free from any interest in the ethanol 
producer's business.
    (3) The ethanol producer shall be free from any interest in the 
third party's business.
    (4) Use of a third party that is debarred, suspended, or proposed 
for debarment pursuant to the Government-wide Debarment and Suspension 
regulations, 40 CFR part 32, or the Debarment, Suspension and 
Ineligibility provisions of the Federal Acquisition Regulations, 48 
CFR, part 9, subpart 9.4, shall be deemed noncompliance with the 
requirements of this section.
    (d) The ethanol producer must obtain the written verification 
required under paragraph (a)(1) of this section by February 28 of the 
year following the first year in which the ethanol producer claims to 
be producing cellulosic biomass ethanol or waste derived ethanol.
    (e) The verification in paragraph (a)(2) of this section is 
required for each calendar year that the ethanol producer claims to be 
producing cellulosic biomass ethanol or waste derived ethanol. The 
ethanol producer must obtain the written verification required under 
paragraph (a)(2) of this section by February 28 for the previous 
calendar year.
    (f) The ethanol producer must retain records of the verifications 
required under paragraph (a) of this section, as required in Sec.  
80.1151(c)(5).
    (g) The independent third party shall retain all records pertaining 
to the verification required under this section for a period of five 
years from the date of creation and shall deliver such records to the 
Administrator upon request.


Sec. Sec.  80.1156 through 80.1159  [Reserved]

0
14. Sections 80.1156 through 80.1159 are reserved.


0
15. Sections 80.1160 and 80.1161 are added to read as follows:


Sec.  80.1160  What acts are prohibited under the RFS program?

    (a) Renewable fuels producer or importer violation. Except as 
provided in Sec.  80.1154, no person shall produce or

[[Page 24004]]

import a renewable fuel without assigning the proper RIN value or 
identifying it by a RIN number as required under Sec.  80.1126.
    (b) RIN generation and transfer violations. No person shall do any 
of the following:
    (1) Improperly generate a RIN (i.e., generate a RIN for which the 
applicable renewable fuel volume was not produced).
    (2) Create or transfer to any person a RIN that is invalid under 
Sec.  80.1131.
    (3) Transfer to any person a RIN that is not properly identified as 
required under Sec.  80.1125.
    (4) Transfer to any person a RIN with a K code of 1 without 
transferring an appropriate volume of renewable fuel to the same person 
on the same day.
    (c) RIN use violations. No person shall do any of the following:
    (1) Fail to acquire sufficient RINs, or use invalid RINs, to meet 
the party's renewable fuel volume obligation under Sec.  80.1127.
    (2) Fail to acquire sufficient RINs to meet the party's renewable 
fuel volume obligation under Sec.  80.1130.
    (3) Use a validly generated RIN to meet the party's renewable fuel 
volume obligation under Sec.  80.1127, or separate and transfer a 
validly generated RIN, where the party ultimately uses the renewable 
fuel volume associated with the RIN in a heater or boiler.
    (d) RIN retention violation. No person shall retain RINs in 
violation of the requirements in Sec.  80.1128(a)(5).
    (e) Causing a violation. No person shall cause another person to 
commit an act in violation of any prohibited act under this section.


Sec.  80.1161  Who is liable for violations under the RFS program?

    (a) Persons liable for violations of prohibited acts. (1) Any 
person who violates a prohibition under Sec.  80.1160(a) through (d) is 
liable for the violation of that prohibition.
    (2) Any person who causes another person to violate a prohibition 
under Sec.  80.1160(a) through (d) is liable for a violation of Sec.  
80.1160(e).
    (b) Persons liable for failure to meet other provisions of this 
subpart. (1) Any person who fails to meet a requirement of any 
provision of this subpart is liable for a violation of that provision.
    (2) Any person who causes another person to fail to meet a 
requirement of any provision of this subpart is liable for causing a 
violation of that provision.
    (c) Parent corporation liability. Any parent corporation is liable 
for any violation of this subpart that is committed by any of its 
subsidiaries.
    (d) Joint venture liability. Each partner to a joint venture is 
jointly and severally liable for any violation of this subpart that is 
committed by the joint venture operation.


Sec.  80.1162  [Reserved]

0
16. Section 80.1162 is reserved.


0
17. Sections 80.1163 through 80.1167 are added to read as follows:

Subpart K--Renewable Fuel Standard

* * * * *
Sec.
80.1163 What penalties apply under the RFS program?
80.1164 What are the attest engagement requirements under the RFS 
program?
80.1165 What are the additional requirements under this Subpart for 
a foreign small refiner?
80.1166 What are the additional requirements under this subpart for 
a foreign producer of cellulosic biomass ethanol or waste derived 
ethanol?
80.1167 What are the additional requirements under this subpart for 
a foreign RIN owner?
* * * * *


Sec.  80.1163  What penalties apply under the RFS program?

    (a) Any person who is liable for a violation under Sec.  80.1161 is 
subject to a civil penalty of up to $32,500, as specified in sections 
205 and 211(d) of the Clean Air Act, for every day of each such 
violation and the amount of economic benefit or savings resulting from 
each violation.
    (b) Any person liable under Sec.  80.1161(a) for a violation of 
Sec.  80.1160(c) for failure to meet a renewable volume obligation, or 
Sec.  80.1160(e) for causing another party to fail to meet a renewable 
volume obligation, during any averaging period, is subject to a 
separate day of violation for each day in the averaging period.
    (c) Any person liable under Sec.  80.1161(b) for failure to meet, 
or causing a failure to meet, a requirement of any provision of this 
subpart is liable for a separate day of violation for each day such a 
requirement remains unfulfilled.


Sec.  80.1164  What are the attest engagement requirements under the 
RFS program?

    The requirements regarding annual attest engagements in Sec. Sec.  
80.125 through 80.127, and 80.130, also apply to any attest engagement 
procedures required under this subpart. In addition to any other 
applicable attest engagement procedures, the following annual attest 
engagement procedures are required under this subpart.
    (a) The following attest procedures shall be completed for any 
obligated party as stated in Sec.  80.1106(a) or exporter of renewable 
fuel that is subject to the renewable fuel standard under Sec.  
80.1105:
    (1) Annual compliance demonstration report. (i) Obtain and read a 
copy of the annual compliance demonstration report required under Sec.  
80.1152(a)(1) which contains information regarding all the following:
    (A) The obligated party's volume of finished gasoline, reformulated 
gasoline blendstock for oxygenate blending (RBOB), and conventional 
gasoline blendstock that becomes finished conventional gasoline upon 
the addition of oxygenate (CBOB) produced or imported during the 
reporting year.
    (B) Renewable volume obligation (RVO).
    (C) RINs used for compliance.
    (ii) Obtain documentation of any volumes of renewable fuel used in 
gasoline during the reporting year; compute and report as a finding the 
volumes of renewable fuel represented in these documents.
    (iii) Compare the volumes of gasoline reported to EPA in the report 
required under Sec.  80.1152(a)(1) with the volumes, excluding any 
renewable fuel volumes, contained in the inventory reconciliation 
analysis under Sec.  80.133.
    (iii) Verify that the production volume information in the 
obligated party's annual summary report required under Sec.  
80.1152(a)(1) agrees with the volume information, excluding any 
renewable fuel volumes, contained in the inventory reconciliation 
analysis under Sec.  80.133.
    (iv) Compute and report as a finding the obligated party's RVO, and 
any deficit RVO carried over from the previous year or carried into the 
subsequent year, and verify that the values agree with the values 
reported to EPA.
    (v) Obtain documentation for all RINs used for compliance during 
the year being reviewed; compute and report as a finding the RIN 
numbers and year of generation of RINs represented in these documents; 
and state whether this information agrees with the report to EPA.
    (2) RIN transaction reports. (i) Obtain and read copies of a 
representative sample of all RIN transaction reports required under 
Sec.  80.1152(a)(2) for the compliance year.
    (ii) Obtain contracts or other documents for the representative 
sample of RIN transactions; compute and report as a finding the 
transaction types, transaction dates, and RINs traded; and state 
whether the information agrees with the party's reports to EPA.
    (3) Gallon-RIN activity reports. (i) Obtain and read copies of all 
quarterly gallon-RIN activity reports required

[[Page 24005]]

under Sec.  80.1152(a)(3) for the compliance year.
    (ii) Obtain documentation of total RINs (including current-year 
RINs and previous-year RINs) owned at the start of the quarter, 
purchased, used for compliance, sold, expired and retired during the 
quarter being reviewed, and owned at the end of the quarter; compute 
and report as a finding the total RINs owned at the start and end of 
the quarter, purchased, used for compliance, sold, expired and retired 
as represented in these documents; and state whether this information 
agrees with the party's reports to EPA.
    (b) The following attest procedures shall be completed for any 
renewable fuel producer or importer:
    (1) RIN-generation reports. (i) Obtain and read copies of the 
quarterly RIN generation reports required under Sec.  80.1152(b)(1) for 
the compliance year.
    (ii) Obtain production data for each renewable fuel batch produced 
during the year being reviewed; compute and report as a finding the RIN 
numbers, production dates, types, volumes of denaturant and applicable 
equivalence values, and production volumes for each batch; and state 
whether this information agrees with the party's reports to EPA.
    (iii) Verify that the proper number of RINs were generated and 
assigned for each batch of renewable fuel produced, as required under 
Sec.  80.1126.
    (iv) Obtain product transfer documents for each renewable fuel 
batch produced during the year being reviewed; report as a finding any 
product transfer document that did not include the RIN for the batch.
    (2) RIN transaction reports. (i) Obtain and read copies of a 
representative sample of the RIN transaction reports required under 
Sec.  80.1152(b)(2) for the compliance year.
    (ii) Obtain contracts or other documents for the representative 
sample of RIN transactions; compute and report as a finding the 
transaction types, transaction dates, and the RINs traded; and state 
whether this information agrees with the party's reports to EPA.
    (3) Gallon-RIN activity reports. (i) Obtain and read copies of the 
quarterly gallon-RIN activity reports required under Sec.  
80.1152(b)(3) for the compliance year.
    (ii) Obtain documentation of total RINs (including current-year 
RINs and previous-year RINs) owned at the start of the quarter, 
purchased, sold, expired and retired during the quarter being reviewed, 
and owned at the end of the quarter; compute and report as a finding 
the total RINs owned at the start and end of the quarter, purchased, 
used for compliance, sold, expired and retired as represented in these 
documents; and state whether this information agrees with the party's 
reports to EPA.
    (c) The following attest procedures shall be completed for any 
party other than an obligated party or renewable fuel producer or 
importer that owns any RINs during a calendar year.
    (1) RIN transaction reports. (i) Obtain and read copies of a 
representative sample of the RIN transaction reports required under 
Sec.  80.1152(c)(1) for the compliance year.
    (ii) Obtain contracts or other documents for the representative 
sample of RIN transactions; compute and report as a finding the 
transaction types, transaction dates, and the RINs traded; and state 
whether this information agrees with the party's reports to EPA.
    (2) Gallon-RIN activity reports. (i) Obtain and read copies of the 
gallon-RIN activity reports required under Sec.  80.1152(c)(2) for the 
compliance year.
    (ii) Obtain documentation of total RINs (including current-year 
RINs and previous-year RINs) owned at the start of the quarter, 
purchased, sold, expired and retired during the quarter being reviewed, 
and owned at the end of the quarter; compute and report as a finding 
the total RINs owned at the start and end of the quarter, purchased, 
used for compliance, sold, expired and retired as represented in these 
documents; and state whether this information agrees with the party's 
reports to EPA.
    (d) The following submission dates apply to the attest engagements 
required under this section.
    (1) For each compliance year, each party subject to the attest 
engagement requirements under this section shall cause the reports 
required under this section to be submitted to EPA by May 31 of the 
year following the compliance year.
    (2) For the 2007 compliance year only, the attest engagement 
required under paragraph (a) of this section may be submitted to EPA 
with the attest engagement for the 2008 compliance year.


Sec.  80.1165  What are the additional requirements under this subpart 
for a foreign small refiner?

    (a) Definitions. The following definitions apply for this subpart:
    (1) Foreign refinery is a refinery that is located outside the 
United States, the Commonwealth of Puerto Rico, the U.S. Virgin 
Islands, Guam, American Samoa, and the Commonwealth of the Northern 
Mariana Islands (collectively referred to in this section as ``the 
United States'').
    (2) Foreign refiner is a person that meets the definition of 
refiner under Sec.  80.2(i) for a foreign refinery.
    (3) RFS-FRGAS is gasoline produced at a foreign refinery that has 
received a small refinery exemption under Sec.  80.1141 or a small 
refiner exemption under Sec.  80.1142 that is imported into the United 
States.
    (4) Non-RFS-FRGAS is one of the following:
    (i) Gasoline produced at a foreign refinery that has received a 
small refinery exemption under Sec.  80.1141 or a small refiner 
exemption under Sec.  80.1142 that is not imported into the United 
States.
    (ii) Gasoline produced at a foreign refinery that has not received 
a small refinery exemption under Sec.  80.1141 or small refiner 
exemption under Sec.  80.1142.
    (5) A foreign small refiner is a foreign refiner that has received 
a small refinery exemption under Sec.  80.1141 for one or more of its 
refineries or a small refiner exemption under Sec.  80.1142.
    (b) General requirements for RFS-FRGAS foreign small refineries and 
small refiners.
    (1) A foreign small refiner must designate, at the time of 
production, each batch of gasoline produced at the foreign refinery 
that is exported for use in the United States as RFS-FRGAS; and
    (2) Meet all requirements that apply to refiners who have received 
a small refinery or small refiner exemption under this subpart.
    (c) Designation, foreign refiner certification, and product 
transfer documents. (1) Any foreign small refiner must designate each 
batch of RFS-FRGAS as such at the time the gasoline is produced.
    (2) On each occasion when RFS-FRGAS is loaded onto a vessel or 
other transportation mode for transport to the United States, the 
foreign refiner shall prepare a certification for each batch of RFS-
FRGAS that meets all the following requirements:
    (i) The certification shall include the report of the independent 
third party under paragraph (d) of this section, and all the following 
additional information:
    (A) The name and EPA registration number of the refinery that 
produced the RFS-FRGAS.
    (B) [Reserved]
    (ii) The identification of the gasoline as RFS-FRGAS.
    (iii) The volume of RFS-FRGAS being transported, in gallons.
    (3) On each occasion when any person transfers custody or title to 
any RFS-FRGAS prior to its being imported into the United States, it 
must include all the following information as part of the product 
transfer document information:

[[Page 24006]]

    (i) Designation of the gasoline as RFS-FRGAS.
    (ii) The certification required under paragraph (c)(2) of this 
section.
    (d) Load port independent testing and refinery identification. (1) 
On each occasion that RFS-FRGAS is loaded onto a vessel for transport 
to the United States the foreign small refiner shall have an 
independent third party do all the following:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms.
    (ii) Determine the volume of RFS-FRGAS loaded onto the vessel 
(exclusive of any tank bottoms before loading).
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery.
    (iv) Determine the name and country of registration of the vessel 
used to transport the RFS-FRGAS to the United States.
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (vi) Review original documents that reflect movement and storage of 
the RFS-FRGAS from the foreign refinery to the load port, and from this 
review determine:
    (A) The refinery at which the RFS-FRGAS was produced; and
    (B) That the RFS-FRGAS remained segregated from Non-RFS-FRGAS and 
other RFS-FRGAS produced at a different refinery.
    (2) The independent third party shall submit a report to:
    (i) The foreign small refiner containing the information required 
under paragraph (d)(1) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) The Administrator containing the information required under 
paragraph (d)(1) of this section, within thirty days following the date 
of the independent third party's inspection. This report shall include 
a description of the method used to determine the identity of the 
refinery at which the gasoline was produced, assurance that the 
gasoline remained segregated as specified in paragraph (j)(1) of this 
section, and a description of the gasoline's movement and storage 
between production at the source refinery and vessel loading.
    (3) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (d);
    (ii) Be independent under the criteria specified in Sec.  
80.65(f)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities, facilities, 
and documents relevant to compliance with the requirements of this 
paragraph (d).
    (e) Comparison of load port and port of entry testing. (1)(i) Any 
small foreign small refiner and any United States importer of RFS-FRGAS 
shall compare the results from the load port testing under paragraph 
(d) of this section, with the port of entry testing as reported under 
paragraph (k) of this section, for the volume of gasoline, except as 
specified in paragraph (e)(1)(ii) of this section.
    (ii) Where a vessel transporting RFS-FRGAS off loads this gasoline 
at more than one United States port of entry, the requirements of 
paragraph (e)(1)(i) of this section do not apply at subsequent ports of 
entry if the United States importer obtains a certification from the 
vessel owner that the requirements of paragraph (e)(1)(i) of this 
section were met and that the vessel has not loaded any gasoline or 
blendstock between the first United States port of entry and the 
subsequent port of entry.
    (2) If the temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent, the United 
States importer and the foreign small refiner shall not treat the 
gasoline as RFS-FRGAS and the importer shall include the volume of 
gasoline in the importer's RFS compliance calculations.
    (f) Foreign refiner commitments. Any small foreign small refiner 
shall commit to and comply with the provisions contained in this 
paragraph (f) as a condition to being approved for a small refinery or 
small refiner exemption under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Gasoline is produced;
    (B) Documents related to refinery operations are kept; and
    (C) RFS-FRGAS is stored or transported between the foreign refinery 
and the United States, including storage tanks, vessels and pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to all the following:
    (A) The volume of RFS-FRGAS.
    (B) The proper classification of gasoline as being RFS-FRGAS or as 
not being RFS-FRGAS.
    (C) Transfers of title or custody to RFS-FRGAS.
    (D) Testing of RFS-FRGAS.
    (E) Work performed and reports prepared by independent third 
parties and by independent auditors under the requirements of this 
section, including work papers.
    (vi) Inspections and audits by EPA may include taking interviewing 
employees.
    (vii) Any employee of the foreign refiner must be made available 
for interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany 
EPA inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign refiner or any employee of the foreign refiner for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act 
or regulations promulgated thereunder shall be governed by the Clean 
Air Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to 
any civil or criminal enforcement action against the foreign refiner or 
any employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting an application for a small refinery or small refiner 
exemption, or producing and exporting gasoline under such exemption, 
and all other actions to comply with the requirements of this subpart 
relating to such exemption constitute actions or activities covered by 
and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but 
solely with respect to actions instituted against the foreign refiner, 
its agents and employees in any court or other tribunal in the United 
States for conduct that violates the requirements applicable to the 
foreign refiner under this subpart, including conduct that violates the 
False

[[Page 24007]]

Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (6) The foreign refiner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA 
inspectors or auditors, whether EPA employees or EPA contractors, for 
actions performed within the scope of EPA employment related to the 
provisions of this section.
    (7) The commitment required by this paragraph (f) shall be signed 
by the owner or president of the foreign refiner business.
    (8) In any case where RFS-FRGAS produced at a foreign refinery is 
stored or transported by another company between the refinery and the 
vessel that transports the RFS-FRGAS to the United States, the foreign 
refiner shall obtain from each such other company a commitment that 
meets the requirements specified in paragraphs (f)(1) through (f)(7) of 
this section, and these commitments shall be included in the foreign 
refiner's application for a small refinery or small refiner exemption 
under this subpart.
    (g) Sovereign immunity. By submitting an application for a small 
refinery or small refiner exemption under this subpart, or by producing 
and exporting gasoline to the United States under such exemption, the 
foreign refiner, and its agents and employees, without exception, 
become subject to the full operation of the administrative and judicial 
enforcement powers and provisions of the United States without 
limitation based on sovereign immunity, with respect to actions 
instituted against the foreign refiner, its agents and employees in any 
court or other tribunal in the United States for conduct that violates 
the requirements applicable to the foreign refiner under this subpart, 
including conduct that violates the False Statements Accountability Act 
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 
U.S.C. 7413).
    (h) Bond posting. Any foreign refiner shall meet the requirements 
of this paragraph (h) as a condition to approval of a small foreign 
refinery or small foreign refiner exemption under this subpart.
    (1) The foreign refiner shall post a bond of the amount calculated 
using the following equation:

Bond = G * $0.01

Where:

Bond = amount of the bond in United States dollars.
G = the largest volume of gasoline produced at the foreign refinery 
and exported to the United States, in gallons, during a single 
calendar year among the most recent of the following calendar years, 
up to a maximum of five calendar years: The calendar year 
immediately preceding the date the refinery's application is 
submitted, the calendar year the application is submitted, and each 
succeeding calendar year.

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party 
surety agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign refiner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement; 
or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative 
commitment.
    (3) Bonds posted under this paragraph (h) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds''; 
and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of latest annual reporting period 
that the foreign refiner produces gasoline pursuant to the requirements 
of this subpart.
    (4) On any occasion a foreign refiner bond is used to satisfy any 
judgment, the foreign refiner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (5) If the bond amount for a foreign refiner increases, the foreign 
refiner shall increase the bond to cover the shortfall within 90 days 
of the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (i) English language reports. Any document submitted to EPA by a 
foreign refiner shall be in English language, or shall include an 
English language translation.
    (j) Prohibitions. (1) No person may combine RFS-FRGAS with any Non-
RFS-FRGAS, and no person may combine RFS-FRGAS with any RFS-FRGAS 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (k) of this section.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (j)(1) of this section, or 
that otherwise violates the requirements of this section.
    (k) United States importer requirements. Any United States importer 
of RFS-FRGAS shall meet the following requirements:
    (1) Each batch of imported RFS-FRGAS shall be classified by the 
importer as being RFS-FRGAS.
    (2) Gasoline shall be classified as RFS-FRGAS according to the 
designation by the foreign refiner if this designation is supported by 
product transfer documents prepared by the foreign refiner as required 
in paragraph (c) of this section. Additionally, the importer shall 
comply with all requirements of this subpart applicable to importers.
    (3) For each gasoline batch classified as RFS-FRGAS, any United 
States importer shall have an independent third party do all the 
following:
    (i) Determine the volume of gasoline in the vessel.
    (ii) Use the foreign refiner's RFS-FRGAS certification to determine 
the name and EPA-assigned registration number of the foreign refinery 
that produced the RFS-FRGAS.
    (iii) Determine the name and country of registration of the vessel 
used to transport the RFS-FRGAS to the United States.
    (iv) Determine the date and time the vessel arrives at the United 
States port of entry.
    (4) Any importer shall submit reports within 30 days following the 
date any vessel transporting RFS-FRGAS arrives at the United States 
port of entry to:
    (i) The Administrator containing the information determined under 
paragraph (k)(3) of this section; and
    (ii) The foreign refiner containing the information determined 
under paragraph (k)(3)(i) of this section, and including identification 
of the port at which the product was off loaded.
    (5) Any United States importer shall meet all other requirements of 
this subpart for any imported gasoline that is not classified as RFS-
FRGAS under paragraph (k)(2) of this section.
    (l) Truck imports of RFS-FRGAS produced at a foreign refinery. (1) 
Any refiner whose RFS-FRGAS is transported into the United States by 
truck may petition EPA to use alternative procedures to meet all the 
following requirements:

[[Page 24008]]

    (i) Certification under paragraph (c)(2) of this section.
    (ii) Load port and port of entry testing requirements under 
paragraphs (d) and (e) of this section.
    (iii) Importer testing requirements under paragraph (k)(3) of this 
section.
    (2) These alternative procedures must ensure RFS-FRGAS remains 
segregated from Non-RFS-FRGAS until it is imported into the United 
States. The petition will be evaluated based on whether it adequately 
addresses the following:
    (i) Provisions for monitoring pipeline shipments, if applicable, 
from the refinery, that ensure segregation of RFS-FRGAS from that 
refinery from all other gasoline.
    (ii) Contracts with any terminals and/or pipelines that receive 
and/or transport RFS-FRGAS that prohibit the commingling of RFS-FRGAS 
with Non-RFS-FRGAS or RFS-FRGAS from other foreign refineries.
    (iii) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation, or other criteria, to confirm that all RFS-FRGAS 
remains segregated throughout the distribution system.
    (3) The petition described in this section must be submitted to EPA 
along with the application for a small refinery or small refiner 
exemption under this subpart.
    (m) Additional attest requirements for importers of RFS-FRGAS. The 
following additional procedures shall be carried out by any importer of 
RFS-FRGAS as part of the attest engagement required for importers under 
this subpart K.
    (1) Obtain listings of all tenders of RFS-FRGAS. Agree the total 
volume of tenders from the listings to the gasoline inventory 
reconciliation analysis required in Sec.  80.133(b), and to the volumes 
determined by the third party under paragraph (d) of this section.
    (2) For each tender under paragraph (m)(1) of this section, where 
the gasoline is loaded onto a marine vessel, report as a finding the 
name and country of registration of each vessel, and the volumes of 
RFS-FRGAS loaded onto each vessel.
    (3) Select a sample from the list of vessels identified in 
paragraph (m)(2) of this section used to transport RFS-FRGAS, in 
accordance with the guidelines in Sec.  80.127, and for each vessel 
selected perform the following:
    (i) Obtain the report of the independent third party, under 
paragraph (d) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification and gasoline volume.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry volume results differ by more than the amount allowed 
in paragraph (e)(2) of this section, and determine whether all of the 
requirements of paragraph (e)(2) of this section have been met.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the RFS-FRGAS from the refinery 
to the load port, under paragraph (d) of this section. Obtain tank 
activity records for any storage tank where the RFS-FRGAS is stored, 
and pipeline activity records for any pipeline used to transport the 
RFS-FRGAS prior to being loaded onto the vessel. Use these records to 
determine whether the RFS-FRGAS was produced at the refinery that is 
the subject of the attest engagement, and whether the RFS-FRGAS was 
mixed with any Non-RFS-FRGAS or any RFS-FRGAS produced at a different 
refinery.
    (4) Select a sample from the list of vessels identified in 
paragraph (m)(2) of this section used to transport RFS-FRGAS, in 
accordance with the guidelines in Sec.  80.127, and for each vessel 
selected perform the following:
    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (5) Obtain separate listings of all tenders of RFS-FRGAS, and 
perform the following:
    (i) Agree the volume of tenders from the listings to the gasoline 
inventory reconciliation analysis in Sec.  80.133(b).
    (ii) Obtain a separate listing of the tenders under this paragraph 
(m)(5) where the gasoline is loaded onto a marine vessel. Select a 
sample from this listing in accordance with the guidelines in Sec.  
80.127, and obtain a commercial document of general circulation that 
lists vessel arrivals and departures, and that includes the port and 
date of departure and the ports and dates where the gasoline was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the gasoline was off loaded for each vessel selected.
    (6) In order to complete the requirements of this paragraph (m), an 
auditor shall:
    (i) Be independent of the foreign refiner or importer;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec.  80.125 through 80.127, 80.130, 80.1164, and this 
paragraph (m); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec.  80.125 
through 80.127, 80.130, 80.1164, and this paragraph (m).
    (n) Withdrawal or suspension of foreign refiner status. EPA may 
withdraw or suspend a foreign refiner's small refinery or small refiner 
exemption where:
    (1) A foreign refiner fails to meet any requirement of this 
section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (f)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(h) of this section.
    (o) Additional requirements for applications, reports and 
certificates. Any application for a small refinery or small refiner 
exemption, alternative procedures under paragraph (l) of this section, 
any report, certification, or other submission required under this 
section shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Be signed by the president or owner of the foreign refiner 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on 
behalf of and to bind [NAME OF FOREIGN REFINER] with regard to all 
statements contained herein; (2) that I am aware that the 
information contained herein is being Certified, or submitted to the 
United States Environmental Protection Agency, under the 
requirements of 40 CFR part 80, subpart K, and that the information 
is material for determining compliance under these regulations; and 
(3) that I have read and understand the information being Certified 
or submitted, and this information is true, complete and correct to 
the best of my knowledge and belief after I have taken reasonable 
and appropriate steps to verify the accuracy thereof. I affirm that 
I have read and

[[Page 24009]]

understand the provisions of 40 CFR part 80, subpart K, including 40 
CFR 80.1165 apply to [NAME OF FOREIGN REFINER]. Pursuant to Clean 
Air Act section 113(c) and 18 U.S.C. 1001, the penalty for 
furnishing false, incomplete or misleading information in this 
certification or submission is a fine of up to $10,000 U.S., and/or 
imprisonment for up to five years.''


Sec.  80.1166  What are the additional requirements under this subpart 
for a foreign producer of cellulosic biomass ethanol or waste derived 
ethanol?

    (a) Foreign producer of cellulosic biomass ethanol or waste derived 
ethanol. For purposes of this subpart, a foreign producer of cellulosic 
biomass ethanol or waste derived ethanol is a person located outside 
the United States, the Commonwealth of Puerto Rico, the Virgin Islands, 
Guam, American Samoa, and the Commonwealth of the Northern Mariana 
Islands (collectively referred to in this section as ''the United 
States'') that has been approved by EPA to assign RINs to cellulosic 
biomass ethanol or waste derived ethanol that the foreign producer 
produces and exports to the United States, hereinafter referred to as a 
``foreign producer'' under this section.
    (b) General requirements. (1) An approved foreign producer under 
this section must meet all requirements that apply to cellulosic 
biomass ethanol or waste derived ethanol producers under this subpart, 
except to the extent otherwise specified in paragraph (b)(2) of this 
section.
    (2)(i) The independent third party that conducts the facility 
verification required under Sec.  80.1155(a) must inspect the foreign 
producer's facility and submit a report to EPA which describes in 
detail the physical plant and its operation.
    (ii) The independent third party that conducts the facility 
verification required under Sec.  80.1155(a) must be a licensed 
Professional Engineer in the chemical engineering field, but need not 
be based in the United States. The independent third party must include 
documentation of its qualifications as a licensed Professional Engineer 
in the report required in paragraph (b)(2)(i) of this section.
    (iii) The requirements of paragraphs (b)(2)(i) and (ii) of this 
section must be met before a foreign entity may be approved as a 
foreign producer under this subpart.
    (c) Designation, foreign producer certification, and product 
transfer documents.
    (1) Any approved foreign producer under this section must designate 
each batch of cellulosic biomass ethanol or waste derived ethanol as 
``RFS-FRETH'' at the time the ethanol is produced.
    (2) On each occasion when RFS-FRETH is loaded onto a vessel or 
other transportation mode for transport to the United States, the 
foreign producer shall prepare a certification for each batch of RFS-
FRETH; the certification shall include the report of the independent 
third party under paragraph (d) of this section, and all the following 
additional information:
    (i) The name and EPA registration number of the company that 
produced the RFS-FRETH.
    (ii) The identification of the ethanol as RFS-FRETH.
    (iii) The volume of RFS-FRETH being transported, in gallons.
    (3) On each occasion when any person transfers custody or title to 
any RFS-FRETH prior to its being imported into the United States, it 
must include all the following information as part of the product 
transfer document information:
    (i) Designation of the ethanol as RFS-FRETH.
    (ii) The certification required under paragraph (c)(2) of this 
section.
    (d) Load port independent testing and refinery identification. (1) 
On each occasion that RFS-FRETH is loaded onto a vessel for transport 
to the United States the foreign producer shall have an independent 
third party do all the following:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms.
    (ii) Determine the volume of RFS-FRETH loaded onto the vessel 
(exclusive of any tank bottoms before loading).
    (iii) Obtain the EPA-assigned registration number of the foreign 
producer.
    (iv) Determine the name and country of registration of the vessel 
used to transport the RFS-FRETH to the United States.
    (v) Determine the date and time the vessel departs the port serving 
the foreign producer.
    (vi) Review original documents that reflect movement and storage of 
the RFS-FRETH from the foreign producer to the load port, and from this 
review determine the following:
    (A) The facility at which the RFS-FRETH was produced.
    (B) That the RFS-FRETH remained segregated from Non-RFS-FRETH and 
other RFS-FRETH produced by a different foreign producer.
    (2) The independent third party shall submit a report to the 
following:
    (i) The foreign producer containing the information required under 
paragraph (d)(1) of this section, to accompany the product transfer 
documents for the vessel.
    (ii) The Administrator containing the information required under 
paragraph (d)(1) of this section, within thirty days following the date 
of the independent third party's inspection. This report shall include 
a description of the method used to determine the identity of the 
foreign producer facility at which the ethanol was produced, assurance 
that the ethanol remained segregated as specified in paragraph (j)(1) 
of this section, and a description of the ethanol's movement and 
storage between production at the source facility and vessel loading.
    (3) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (d);
    (ii) Be independent under the criteria specified in Sec.  
80.65(e)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities, facilities and 
documents relevant to compliance with the requirements of this 
paragraph (d).
    (e) Comparison of load port and port of entry testing. (1)(i) Any 
foreign producer and any United States importer of RFS-FRETH shall 
compare the results from the load port testing under paragraph (d) of 
this section, with the port of entry testing as reported under 
paragraph (k) of this section, for the volume of ethanol, except as 
specified in paragraph (e)(1)(ii) of this section.
    (ii) Where a vessel transporting RFS-FRETH off loads the ethanol at 
more than one United States port of entry, the requirements of 
paragraph (e)(1)(i) of this section do not apply at subsequent ports of 
entry if the United States importer obtains a certification from the 
vessel owner that the requirements of paragraph (e)(1)(i) of this 
section were met and that the vessel has not loaded any ethanol between 
the first United States port of entry and the subsequent port of entry.
    (2)(i) If the temperature-corrected volumes determined at the port 
of entry and at the load port differ by more than one percent, the 
number of RINs associated with the ethanol shall be calculated based on 
the lesser of the two volumes in paragraph (e)(1)(i) of this section.
    (ii) Where the port of entry volume is the lesser of the two 
volumes in paragraph (e)(1)(i) of this section, the importer shall 
calculate the difference between the number of RINs originally assigned 
by the foreign producer and

[[Page 24010]]

the number of RINs calculated under Sec.  80.1126 for the volume of 
ethanol as measured at the port of entry, and retire that amount of 
RINs in accordance with paragraph (k)(4) of this section.
    (f) Foreign producer commitments. Any foreign producer shall commit 
to and comply with the provisions contained in this paragraph (f) as a 
condition to being approved as a foreign producer under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign producer facility.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Ethanol is produced;
    (B) Documents related to ethanol producer operations are kept; and
    (C) RFS-FRETH is stored or transported between the foreign producer 
and the United States, including storage tanks, vessels and pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to the following:
    (A) The volume of RFS-FRETH.
    (B) The proper classification of gasoline as being RFS-FRETH;
    (C) Transfers of title or custody to RFS-FRETH.
    (D) Work performed and reports prepared by independent third 
parties and by independent auditors under the requirements of this 
section, including work papers.
    (vi) Inspections and audits by EPA may include interviewing 
employees.
    (vii) Any employee of the foreign producer must be made available 
for interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany 
EPA inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign producer or any employee of the foreign producer for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act 
or regulations promulgated thereunder shall be governed by the Clean 
Air Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to 
any civil or criminal enforcement action against the foreign producer 
or any employee of the foreign producer related to the provisions of 
this section.
    (5) Applying to be an approved foreign producer under this section, 
or producing or exporting ethanol under such approval, and all other 
actions to comply with the requirements of this subpart relating to 
such approval constitute actions or activities covered by and within 
the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with 
respect to actions instituted against the foreign producer, its agents 
and employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign 
producer under this subpart, including conduct that violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (6) The foreign producer, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA 
inspectors or auditors, whether EPA employees or EPA contractors, for 
actions performed within the scope of EPA employment related to the 
provisions of this section.
    (7) The commitment required by this paragraph (f) shall be signed 
by the owner or president of the foreign producer company.
    (8) In any case where RFS-FRETH produced at a foreign producer 
facility is stored or transported by another company between the 
refinery and the vessel that transports the RFS-FRETH to the United 
States, the foreign producer shall obtain from each such other company 
a commitment that meets the requirements specified in paragraphs (f)(1) 
through (7) of this section, and these commitments shall be included in 
the foreign producer's application to be an approved foreign producer 
under this subpart.
    (g) Sovereign immunity. By submitting an application to be an 
approved foreign producer under this subpart, or by producing and 
exporting ethanol to the United States under such approval, the foreign 
producer, and its agents and employees, without exception, become 
subject to the full operation of the administrative and judicial 
enforcement powers and provisions of the United States without 
limitation based on sovereign immunity, with respect to actions 
instituted against the foreign producer, its agents and employees in 
any court or other tribunal in the United States for conduct that 
violates the requirements applicable to the foreign producer under this 
subpart, including conduct that violates the False Statements 
Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of 
the Clean Air Act (42 U.S.C. 7413).
    (h) Bond posting. Any foreign producer shall meet the requirements 
of this paragraph (h) as a condition to approval as a foreign producer 
under this subpart.
    (1) The foreign producer shall post a bond of the amount calculated 
using the following equation:

Bond = G * $ 0.01

Where:

Bond = amount of the bond in U.S. dollars.
G = The largest volume of ethanol produced at the foreign producer's 
facility and exported to the United States, in gallons, during a 
single calendar year among the most recent of the following calendar 
years, up to a maximum of five calendar years: The calendar year 
immediately preceding the date the refinery's application is 
submitted, the calendar year the application is submitted, and each 
succeeding calendar year.

    (2) Bonds shall be posted by any of the following methods:
    (i) Paying the amount of the bond to the Treasurer of the United 
States.
    (ii) Obtaining a bond in the proper amount from a third party 
surety agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign producer, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement.
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States provided EPA agrees in advance as to the alternative commitment.
    (3) Bonds posted under this paragraph (h) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States

[[Page 24011]]

Department of Treasury Circular 570 ''Companies Holding Certificates of 
Authority as Acceptable Sureties on Federal Bonds''; and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of the latest annual reporting 
period that the foreign producer produces ethanol pursuant to the 
requirements of this subpart.
    (4) On any occasion a foreign producer bond is used to satisfy any 
judgment, the foreign producer shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (5) If the bond amount for a foreign producer increases, the 
foreign producer shall increase the bond to cover the shortfall within 
90 days of the date the bond amount changes. If the bond amount 
decreases, the foreign refiner may reduce the amount of the bond 
beginning 90 days after the date the bond amount changes.
    (i) English language reports. Any document submitted to EPA by a 
foreign producer shall be in English language, or shall include an 
English language translation.
    (j) Prohibitions. (1) No person may combine RFS-FRETH with any Non-
RFS-FRETH, and no person may combine RFS-FRETH with any RFS-FRETH 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (k) of this section.
    (2) No foreign producer or other person may cause another person to 
commit an action prohibited in paragraph (j)(1) of this section, or 
that otherwise violates the requirements of this section.
    (k) Requirements for United States importers of RFS-FRETH. Any 
United States importer shall meet the following requirements:
    (1) Each batch of imported RFS-FRETH shall be classified by the 
importer as being RFS-FRETH.
    (2) Ethanol shall be classified as RFS-FRETH according to the 
designation by the foreign producer if this designation is supported by 
product transfer documents prepared by the foreign producer as required 
in paragraph (c) of this section.
    (3) For each ethanol batch classified as RFS-FRETH, any United 
States importer shall have an independent third party do all the 
following:
    (i) Determine the volume of gasoline in the vessel.
    (ii) Use the foreign producer's RFS-FRETH certification to 
determine the name and EPA-assigned registration number of the foreign 
producer that produced the RFS-FRETH.
    (iii) Determine the name and country of registration of the vessel 
used to transport the RFS-FRETH to the United States.
    (iv) Determine the date and time the vessel arrives at the United 
States port of entry.
    (4) Where the importer is required to retire RINs under paragraph 
(e)(2) of this section, the importer must report the retired RINs in 
the applicable reports under Sec.  80.1152.
    (5) Any importer shall submit reports within 30 days following the 
date any vessel transporting RFS-FRETH arrives at the United States 
port of entry to the following:
    (i) The Administrator containing the information determined under 
paragraph (k)(3) of this section.
    (ii) The foreign producer containing the information determined 
under paragraph (k)(3)(i) of this section, and including identification 
of the port at which the product was off loaded, and any RINs retired 
under paragraph (e)(2) of this section.
    (6) Any United States importer shall meet all other requirements of 
this subpart for any imported ethanol or other renewable fuel that is 
not classified as RFS-FRETH under paragraph (k)(2) of this section.
    (l) Truck imports of RFS-FRETH produced by a foreign producer. (1) 
Any foreign producer whose RFS-FRETH is transported into the United 
States by truck may petition EPA to use alternative procedures to meet 
all the following requirements:
    (i) Certification under paragraph (c)(2) of this section.
    (ii) Load port and port of entry testing under paragraphs (d) and 
(e) of this section.
    (iii) Importer testing under paragraph (k)(3) of this section.
    (2) These alternative procedures must ensure RFS-FRETH remains 
segregated from Non-RFS-FRETH until it is imported into the United 
States. The petition will be evaluated based on whether it adequately 
addresses the following:
    (i) Contracts with any facilities that receive and/or transport 
RFS-FRETH that prohibit the commingling of RFS-FRETH with Non-RFS-FRETH 
or RFS-FRETH from other foreign producers.
    (ii) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation to confirm that all RFS-FRETH remains segregated.
    (3) The petition described in this section must be submitted to EPA 
along with the application for approval as a foreign producer under 
this subpart.
    (m) Additional attest requirements for producers of RFS-FRETH. The 
following additional procedures shall be carried out by any producer of 
RFS-FRETH as part of the attest engagement required for renewable fuel 
producers under this subpart K.
    (1) Obtain listings of all tenders of RFS-FRETH. Agree the total 
volume of tenders from the listings to the volumes determined by the 
third party under paragraph (d) of this section.
    (2) For each tender under paragraph (m)(1) of this section, where 
the ethanol is loaded onto a marine vessel, report as a finding the 
name and country of registration of each vessel, and the volumes of 
RFS-FRETH loaded onto each vessel.
    (3) Select a sample from the list of vessels identified in 
paragraph (m)(2) of this section used to transport RFS-FRETH, in 
accordance with the guidelines in Sec.  80.127, and for each vessel 
selected perform the following:
    (i) Obtain the report of the independent third party, under 
paragraph (d) of this section, and of the United States importer under 
paragraph (k) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification and ethanol volume.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry volume results differ by more than the amount allowed 
in paragraph (e) of this section, and determine whether the importer 
retired the appropriate amount of RINs as required under paragraph 
(e)(2) of this section, and submitted the applicable reports under 
Sec.  80.1152 in accordance with paragraph (k)(4) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the RFS-FRETH from the foreign 
producer's facility to the load port, under paragraph (d) of this 
section. Obtain tank activity records for any storage tank where the 
RFS-FRETH is stored, and activity records for any mode of 
transportation used to transport the RFS-FRGAS prior to being loaded 
onto the vessel. Use these records to determine whether the RFS-FRETH 
was produced at the foreign producer's facility that is the subject of 
the attest engagement, and whether the RFS-FRETH was mixed with any 
Non-RFS-FRETH or any RFS-FRETH produced at a different facility.
    (4) Select a sample from the list of vessels identified in 
paragraph (m)(2) of this section used to transport RFS-FRETH, in 
accordance with the guidelines in Sec.  80.127, and for each vessel 
selected perform the following:

[[Page 24012]]

    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (5) Obtain a separate listing of the tenders under this paragraph 
(m)(5) where the gasoline is loaded onto a marine vessel. Select a 
sample from this listing in accordance with the guidelines in Sec.  
80.127, and obtain a commercial document of general circulation that 
lists vessel arrivals and departures, and that includes the port and 
date of departure and the ports and dates where the ethanol was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the ethanol was off loaded for each vessel selected.
    (6) In order to complete the requirements of this paragraph (m) an 
auditor shall:
    (i) Be independent of the foreign producer;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec.  80.125 through 80.127, 80.130, 80.1164, and this 
paragraph (m); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec.  80.125 
through 80.127, 80.130, 80.1164, and this paragraph (m).
    (n) Withdrawal or suspension of foreign producer approval. EPA may 
withdraw or suspend a foreign producer's approval where any of the 
following occur:
    (1) A foreign producer fails to meet any requirement of this 
section.
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (f)(1) of this section.
    (3) A foreign producer asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart.
    (4) A foreign producer fails to pay a civil or criminal penalty 
that is not satisfied using the foreign producer bond specified in 
paragraph (g) of this section.
    (o) Additional requirements for applications, reports and 
certificates. Any application for approval as a foreign producer, 
alternative procedures under paragraph (l) of this section, any report, 
certification, or other submission required under this section shall 
be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Signed by the president or owner of the foreign producer 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on 
behalf of and to bind [insert name of foreign producer] with regard 
to all statements contained herein; (2) that I am aware that the 
information contained herein is being Certified, or submitted to the 
United States Environmental Protection Agency, under the 
requirements of 40 CFR part 80, subpart K, and that the information 
is material for determining compliance under these regulations; and 
(3) that I have read and understand the information being Certified 
or submitted, and this information is true, complete and correct to 
the best of my knowledge and belief after I have taken reasonable 
and appropriate steps to verify the accuracy thereof. I affirm that 
I have read and understand the provisions of 40 CFR part 80, subpart 
K, including 40 CFR 80.1165 apply to [insert name of foreign 
producer]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 
1001, the penalty for furnishing false, incomplete or misleading 
information in this certification or submission is a fine of up to 
$10,000 U.S., and/or imprisonment for up to five years.


Sec.  80.1167  What are the additional requirements under this subpart 
for a foreign RIN owner?

    (a) Foreign RIN owner. For purposes of this subpart, a foreign RIN 
owner is a person located outside the United States, the Commonwealth 
of Puerto Rico, the Virgin Islands, Guam, American Samoa, and the 
Commonwealth of the Northern Mariana Islands (collectively referred to 
in this section as ``the United States'') that has been approved by EPA 
to own RINs.
    (b) General Requirement. An approved foreign RIN owner must meet 
all requirements that apply to persons who own RINs under this subpart.
    (c) Foreign RIN owner commitments. Any person shall commit to and 
comply with the provisions contained in this paragraph (c) as a 
condition to being approved as a foreign RIN owner under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign RIN owner's place of business.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced; and
    (ii) Access will be provided to any location where documents 
related to RINs the foreign RIN owner has obtained, sold, transferred 
or held are kept.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to the following:
    (A) Transfers of title to RINs.
    (B) Work performed and reports prepared by independent auditors 
under the requirements of this section, including work papers.
    (vi) Inspections and audits by EPA may include interviewing 
employees.
    (vii) Any employee of the foreign RIN owner must be made available 
for interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany 
EPA inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign RIN owner or any employee of the foreign RIN owner for 
any action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act 
or regulations promulgated thereunder shall be governed by the Clean 
Air Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to 
any civil or criminal enforcement action against the foreign RIN owner 
or any employee of the foreign RIN owner related to the provisions of 
this section.
    (5) Submitting an application to be a foreign RIN owner, and all 
other actions to comply with the requirements of this subpart 
constitute actions or activities covered by and within the meaning of 
the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to 
actions instituted against the foreign RIN owner, its agents and 
employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign RIN 
owner under this subpart, including conduct

[[Page 24013]]

that violates the False Statements Accountability Act of 1996 (18 
U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 
7413).
    (6) The foreign RIN owner, or its agents or employees, will not 
seek to detain or to impose civil or criminal remedies against EPA 
inspectors or auditors, whether EPA employees or EPA contractors, for 
actions performed within the scope of EPA employment related to the 
provisions of this section.
    (7) The commitment required by this paragraph (c) shall be signed 
by the owner or president of the foreign RIN owner business.
    (d) Sovereign immunity. By submitting an application to be a 
foreign RIN owner under this subpart, the foreign entity, and its 
agents and employees, without exception, become subject to the full 
operation of the administrative and judicial enforcement powers and 
provisions of the United States without limitation based on sovereign 
immunity, with respect to actions instituted against the foreign RIN 
owner, its agents and employees in any court or other tribunal in the 
United States for conduct that violates the requirements applicable to 
the foreign RIN owner under this subpart, including conduct that 
violates the False Statements Accountability Act of 1996 (18 U.S.C. 
1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (e) Bond posting. Any foreign entity shall meet the requirements of 
this paragraph (d) as a condition to approval as a foreign RIN owner 
under this subpart.
    (1) The foreign entity shall post a bond of the amount calculated 
using the following equation:

Bond = G * $0.01

Where:

Bond = amount of the bond in U.S. dollars.
G = The total of the number of gallon-RINs the foreign entity 
expects to sell or transfer during the first calendar year that the 
foreign entity is a RIN owner, plus the number of gallon-RINs the 
foreign entity expects to sell or transfer during the next four 
calendar years. After the first calendar year, the bond amount shall 
be based on the actual number of gallon-RINs sold or transferred 
during the current calendar year and the number held at the 
conclusion of the current averaging year, plus the number of gallon-
RINs sold or transferred during the four most recent calendar years 
preceding the current calendar year. For any year for which there 
were fewer than four preceding years in which the foreign entity 
sold or transferred RINs, the bond shall be based on the total of 
the number of gallon-RINs sold or transferred during the current 
calendar year and the number held at the end of the current calendar 
year, plus the number of gallon-RINs sold or transferred during any 
calendar year preceding the current calendar year, plus the number 
of gallon-RINs expected to be sold or transferred during subsequent 
calendar years, the total number of years not to exceed four 
calendar years in addition to the current calendar year.

    (2) Bonds shall be posted by doing any of the following:
    (i) Paying the amount of the bond to the Treasurer of the United 
States.
    (ii) Obtaining a bond in the proper amount from a third party 
surety agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign RIN owner, provided EPA agrees 
in advance as to the third party and the nature of the surety 
agreement.
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative 
commitment.
    (3) Bonds posted under this paragraph (e) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds''; 
and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of latest reporting period in 
which the foreign RIN owner obtains, sells, transfers or holds RINs.
    (4) On any occasion a foreign RIN owner bond is used to satisfy any 
judgment, the foreign RIN owner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (f) English language reports. Any document submitted to EPA by a 
foreign RIN owner shall be in English language, or shall include an 
English language translation.
    (g) Prohibitions. (1) A foreign RIN owner is prohibited from 
obtaining, selling, transferring or holding any RIN that is in excess 
of the number for which the bond requirements of this section have been 
satisfied.
    (2) Any RIN that is sold, transferred or held that is in excess of 
the number for which the bond requirements of this section have been 
satisfied is an invalid RIN under Sec.  80.1131.
    (3) Any RIN that is obtained from a person located outside the 
United States that is not an approved foreign RIN owner under this 
section is an invalid RIN under Sec.  80.1131.
    (4) No foreign RIN owner or other person may cause another person 
to commit an action prohibited in this paragraph (g), or that otherwise 
violates the requirements of this section.
    (h) Additional attest requirements for foreign RIN owners. The 
following additional requirements apply to any foreign RIN owner as 
part of the attest engagement required for RIN owners under this 
subpart K.
    (1) The attest auditor must be independent of the foreign RIN 
owner.
    (2) The attest auditor must be licensed as a Certified Public 
Accountant in the United States and a citizen of the United States, or 
be approved in advance by EPA based on a demonstration of ability to 
perform the procedures required in Sec. Sec.  80.125 through 80.127, 
80.130, and 80.1164.
    (3) The attest auditor must sign a commitment that contains the 
provisions specified in paragraph (c) of this section with regard to 
activities and documents relevant to compliance with the requirements 
of Sec. Sec.  80.125 through 80.127, 80.130, and 80.1164.
    (i) Withdrawal or suspension of foreign RIN owner status. EPA may 
withdraw or suspend its approval of a foreign RIN owner where any of 
the following occur:
    (1) A foreign RIN owner fails to meet any requirement of this 
section, including, but not limited to, the bond requirements.
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (c)(1) of this section.
    (3) A foreign RIN owner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart.
    (4) A foreign RIN owner fails to pay a civil or criminal penalty 
that is not satisfied using the foreign RIN owner bond specified in 
paragraph (e) of this section.
    (j) Additional requirements for applications, reports and 
certificates. Any application for approval as a foreign RIN owner, any 
report, certification, or other submission required under this section 
shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Signed by the president or owner of the foreign RIN owner 
company, or

[[Page 24014]]

that person's immediate designee, and shall contain the following 
declaration:

    I hereby certify: (1) That I have actual authority to sign on 
behalf of and to bind [insert name of foreign RIN owner] with regard 
to all statements contained herein; (2) that I am aware that the 
information contained herein is being Certified, or submitted to the 
United States Environmental Protection Agency, under the 
requirements of 40 CFR part 80, subpart K, and that the information 
is material for determining compliance under these regulations; and 
(3) that I have read and understand the information being Certified 
or submitted, and this information is true, complete and correct to 
the best of my knowledge and belief after I have taken reasonable 
and appropriate steps to verify the accuracy thereof. I affirm that 
I have read and understand the provisions of 40 CFR part 80, subpart 
K, including 40 CFR 80.1167 apply to [insert name of foreign RIN 
owner]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, 
the penalty for furnishing false, incomplete or misleading 
information in this certification or submission is a fine of up to 
$10,000 U.S., and/or imprisonment for up to five years.
[FR Doc. E7-7140 Filed 4-30-07; 8:45 am]

BILLING CODE 6560-50-P
