FR Doc E7-7140

[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

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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:

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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.
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\1\ North American Industry Classification System (NAICS).
\2\ Standard Industrial Classification (SIC) system code.

This table is not intended to be exhaustive, but 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

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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

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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

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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

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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:

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