[Federal Register Volume 71, Number 184 (Friday, September 22, 2006)]
[Proposed Rules]
[Pages 55552-55651]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-7887]
[[Page 55551]]
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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; Proposed Rule
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 /
Proposed Rules
[[Page 55552]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 80
[EPA-OAR-2005-0161; FRL-8218-8]
RIN 2060-AN76
Regulation of Fuels and Fuel Additives: Renewable Fuel Standard
Program
AGENCY: Environmental Protection Agency (EPA).
ACTION: Notice of proposed rulemaking.
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SUMMARY: Under the Clean Air Act, as amended by 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
needs to be used in each year, with the total volume increasing over
time. In this context, it is expected to simultaneously reduce
dependence on foreign sources of petroleum, increase domestic sources
of energy, and help us make progress in moving beyond a petroleum-based
economy. The increased use of renewable fuels such as ethanol and
biodiesel is also expected to have the added benefit of providing an
expanded market for agricultural products such as corn and soybeans,
expanding economic benefits for our nation's agricultural sector. Based
on our analysis, there is also reason to believe that the expanded use
of renewable fuels will provide reductions in carbon dioxide emissions
and some air toxics emissions, such as benzene, from the transportation
sector, while other emissions may increase.
This action proposes regulations designed to ensure that refiners,
blenders, and importers of gasoline will use enough renewable fuel each
year so that this total volume requirement is met. Our proposal
describes the standard that will apply to these parties and the
renewable fuels that qualify for compliance. The regulations would also
establish a trading program that would be a critical 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: Comments: Comments must be received on or before November 12,
2006. Under the Paperwork Reduction Act, comments on the information
collection provisions must be received by OMB on or before October 30,
2006.
Hearing: A public hearing will be held at 10 a.m. (Central) on
October 13, 2006 at the Sheraton Gateway Suites Chicago O'Hare in
Rosemont, IL. To request to speak at a public hearing, send a request
to the contact in FOR FURTHER INFORMATION CONTACT by October 4, 2006.
ADDRESSES: Comments: Submit your comments, identified by Docket ID No.
EPA-OAR-2005-0161, by one of the following methods:
http://www.regulations.gov: Follow the on-line
instructions for submitting comments.
E-mail: [email protected].
Mail: U.S. Environmental Protection Agency, EPA West (Air
Docket), 1200 Pennsylvania Ave., NW., Room B108, Mail Code 6102T,
Washington, DC 20460, Attention Docket ID No. OAR-2005-0161. Please
include a total of 2 copies. In addition, please mail a copy of your
comments on the information collection provisions to the Office of
Information and Regulatory Affairs, Office of Management and Budget
(OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC
20503.
Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room
B102, 1301 Constitution Ave., NW., Washington DC. Such deliveries are
only accepted during the Docket's normal hours of operation, and
special arrangements should be made for deliveries of boxed
information.
Instructions: Direct your comments to Docket ID No. EPA-OAR-2005-
0161. EPA's policy is that all comments received will be included in
the public docket without change and may be made available online at
www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through www.regulations.gov or e-mail.
The www.regulations.gov Web site is an ``anonymous access'' system,
which means EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an e-
mail comment directly to EPA without going through www.regulations.gov
your e-mail address will be automatically captured and included as part
of the comment that is placed in the public docket and made available
on the Internet. If you submit an electronic comment, EPA recommends
that you include your name and other contact information in the body of
your comment and with any disk or CD-ROM you submit. If EPA cannot read
your comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses.
Docket: All documents in the docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the EPA Docket Center, EPA/
DC, EPA West, Room B102, 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 Docket telephone number
is (202) 566-1742. The telephone number for the Public Reading Room is
(202) 566-1744.
Note: The EPA Docket Center suffered damage due to flooding
during the last week of June 2006. The Docket Center is continuing
to operate. However, during the cleanup, there will be temporary
changes to Docket Center telephone numbers, addresses, and hours of
operation for people who wish to make hand deliveries or visit the
Public Reading Room to view documents. Consult EPA's Federal
Register notice at 71 FR 38147 (July 5, 2006) or the EPA Web site at
http://www.epa.gov/epahome/dockets.htm for current information on
docket operations, locations and telephone numbers. The Docket
Center's mailing address for U.S. mail and the procedure for
submitting comments to www.regulations.gov are not affected by the
flooding and will remain the same.
Hearing: The hearing will be held at 10 a.m. (Central) on October
13, 2006 at the Sheraton Gateway Suites Chicago O'Hare, 6501 North
Mannheim Road, Rosemont, Illinois 60018. To request to speak at a
public hearing, send a request to the contact in FOR FURTHER
INFORMATION CONTACT.
FOR FURTHER INFORMATION CONTACT: Julia MacAllister, U.S. EPA, National
Vehicle and Fuel Emissions Laboratory, 2000 Traverwood, Ann Arbor, MI
48105; Telephone (734) 214-4131, FAX (734) 214-4816, E-mail
[email protected].
SUPPLEMENTARY INFORMATION:
I. General Information
A. Does This Action Apply to Me?
Entities potentially affected by this proposed action include those
involved
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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 proposed action. Other types of
entities not listed in the table could also be affected. To decide
whether your organization might be affected if this proposed action is
finalized, 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.
B. What Should I Consider as I Prepare my Comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through
www.regulations.gov or e-mail. Clearly mark the part or all of the
information that you claim to be CBI. For CBI information in a disk or
CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as
CBI and then identify electronically within the disk or CD ROM the
specific information that is claimed as CBI. In addition to one
complete version of the comment that includes information claimed as
CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2.
2. Tips for Preparing Your Comments. When submitting comments,
remember to:
Identify the rulemaking by docket number and other
identifying information (subject heading, Federal Register date and
page number).
Follow directions--The agency may ask you to respond to
specific questions or organize comments by referencing a Code of
Federal Regulations (CFR) part or section number.
Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns, and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
3. Docket Copying Costs. A reasonable fee may be charged by EPA for
copying docket materials, as provided in 40 CFR part 2.
Table of Contents
I. Background
A. The Role of Renewable Fuels in the Transportation Sector
B. Requirements in the Energy Policy Act
C. Default Standard Applicable to 2006
D. Development of the Proposal
II. Overview of the Proposal
A. Impacts of Increased Reliance on Renewable Fuels
1. Renewable Fuel Volumes Scenarios Analyzed
2. Emissions
3. Economic Impacts
4. Greenhouse Gases and Fossil Fuel Consumption
5. Potential Water Quality Impacts
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 Renewable Fuels
5. How Will Compliance Be Determined?
6. How Would the Trading Program Work?
7. How Would the Program Be Enforced?
C. Voluntary 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
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 Run Mostly With
Biomass-Based Fuel
c. Ethanol That Is Made From the Non-Cellulosic Portions of
Animal, Other Waste, and Municipal Waste
2. What Is Biodiesel?
a. Biodiesel (Mono-Alkyl Esters)
b. Non-Ester Renewable Diesel
3. Is Motor Fuel That is Made From a Renewable Feedstock a
Renewable Fuel?
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 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
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b. Alternative Approach to Tracking Batches
2. Generating RINs and Assigning Them to Batches
a. Form of Renewable Identification Numbers
b. Generating Extra-Value 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 Would the Agency Verify Compliance?
E. How Are RINs Distributed and Traded?
1. Distribution of RINs With Batches of Renewable Fuel
a. Responsibilities of Renewable Fuel Producers and Importers
b. Responsibilities of Parties That Buy, Sell, or Handle
Renewable Fuels
i. Batch Splits
ii. Batch Mergers
2. Separation of RINs From Batches
3. Distribution of Separated RINs
4. Alternative Approaches to RIN Distribution
a. Producer With Direct Transfer of RINs
b. Producer With Open RIN Market
c. First Purchaser
d. Owner at Time of Blending
e. Blender at Time of Blending
IV. Registration, Recordkeeping, and Reporting Requirements
A. Introduction
B. Requirements for Obligated Parties and Exporters of Renewable
Fuels
1. Registration
2. Reporting
3. Recordkeeping
C. Requirements for Producers and Importers of Renewable Fuel
1. Registration
2. Reporting
3. Recordkeeping
D. Requirements for Other Parties Who Own RINs
1. Registration
2. Reporting
3. Recordkeeping
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. Production Capacity of Cellulosic Ethanol
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
c. Ethanol's Blending Cost
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. RVP Cost for Blending Ethanol Into Summertime RFG
2. Cost Savings for Phasing Out Methyl Tertiary Butyl Ether
(MTBE)
3. Production of Alkylate From MTBE Feedstocks
4. Changes in Refinery Produced Gasoline Volume and Its Costs
5. Overall Impact on Fuel Cost
a. Cost Without Ethanol Subsidies
b. Gasoline Costs Including Ethanol Consumption Tax Subsidies
c. Cost Sensitivity Case Assuming $70 per Barrel Crude Oil
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 7.2 Billion Gallon Ethanol Use on Ozone
2. Particulate Matter
IX. Impacts on Fossil Fuel Consumption and Related Implications
A. Lifecycle Modeling
1. Modifications to GREET Assumptions
a. Wet-Mill Versus Dry Mill Ethanol Plants
b. Coal Versus Natural Gas in Ethanol Plants
c. Ethanol Production Yield
2. Controversy Concerning the Ethanol Energy Balance
B. Overview of Methodology
1. Amount of Conventional Fuel Replaced By Renewable Fuel (R)
2. Lifecycle Impacts of Conventional Fuel Use (LC)
3. Displacement Indexes (DI)
C. Impacts of Increased Renewable Fuel Use
1. Fossil Fuels and Petroleum
2. Greenhouse Gases and Carbon Dioxide
D. Implications of Reduced Imports of Petroleum Products
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--Small Refiners Versus Small Refineries
3. Summary of Potentially Affected Small Entities
4. Impact of the Regulations on Small Entities
5. Small Refiner Outreach
6. 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
XIII. Statutory Authority
I. Background
This section describes the required elements of the renewable fuel
program, also known as the Renewable Fuel Standard (RFS) program, as
stipulated in Section 211(o) of the Clean Air Act (CAA) as amended by
the Energy Policy Act of 2005 (the Energy Act or the Act).
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 renewables 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
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monoxide emissions. Many of these areas also blended ethanol during the
winter months to help meet this new standard, such as Denver and
Phoenix. As a result of these programs, and other factors, currently
all areas requiring RFG or winter oxygenated fuels are blending ethanol
at some level to support meeting the clean fuel requirements.
Today, the role and importance of renewable fuels in the
transportation sector continues 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 has 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 has
renewed interest in renewable transportation fuels. The passage of the
Energy Policy Act of 2005 demonstrated a strong commitment on the part
of U.S. policymakers to consider additional means of supporting
renewable fuels as a supplement to petroleum-based fuels in the
transportation sector. The RFS program is such a program.
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 to increase the
use of renewable fuels in motor vehicle fuels 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 in moving beyond a petroleum-
based economy.
The increased use of renewable fuels such as ethanol and biodiesel
is also expected to have the added benefit of providing an expanded
market for agricultural products such as corn and soybeans. Based on
our analysis, there is also an expectation that the expanded use of
renewable fuels will provide reductions in carbon dioxide emissions and
air toxics emissions such as benzene from the transportation sector,
while other emissions such as hydrocarbons and oxides of nitrogen may
increase.
The level of the renewable fuels standard set forth by Congress
works in conjunction with other provisions that were enacted as part of
the Energy Act. In particular, the level of the renewable fuel standard
more than offset the possible loss in demand for renewable fuels
occasioned by the Act's repeal of the oxygen content mandate in the
reformulated gasoline program while allowing greater flexibility in how
renewable fuels were blended into the nation's fuel supply. The
renewable fuel standard additionally created 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 is an important first step
in U.S. efforts to move toward energy independence. The RFS standard
provides the certainty that at least a minimum amount of renewable fuel
will be used in the U.S., which in turn provides investment certainty
for the growth in production capacity of renewable fuels. However, the
RFS program is not the only thing 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 were forced
to switch to ethanol to satisfy the oxygen content mandate for their
reformulated gasoline in the U.S., causing a large, quick 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 has been 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 dramatic increase in the
cost of crude oil. In the last few years, both crude oil prices and
crude oil price forecasts have increased dramatically. 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 statutory goal of the RFS program is to provide an
important foundation for ongoing investment in renewable fuel
production. However, market demand for renewable fuels is expected to
exceed the statutory minimums. We believe we are proposing a program
structure that could continue to 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 provides the statutory basis
for the RFS program. This provision was added to the CAA as 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
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2006.................................................... 4.0
2007.................................................... 4.7
2008.................................................... 5.4
2009.................................................... 6.1
2010.................................................... 6.8
2011.................................................... 7.4
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2012.................................................... 7.5
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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 a 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.
Renewable fuels are defined in the Act primarily on the basis of
the feedstock. In general, renewable fuels must be a motor vehicle fuel
that is produced from plant or animal products or wastes, as opposed to
fossil fuel sources. The Act 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 ensuring is introduced
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 fact that small refineries are exempted from the
program until 2011, but must take into account the use of renewable
fuel by those small refineries.
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 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 also determine who can generate credits and under
what conditions, how credits may be transferred from one party to
another, and in certain cases 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. Default Standard Applicable to 2006
The Energy Act was enacted in August of 2005 and included
provisions for a renewable fuel program that was to begin in January of
2006. We recognized that a rulemaking implementing the full RFS
program, including both program design and the various analyses
necessary, would require a substantial effort involving many
stakeholders. This process was expected to take longer than one year,
and as a result we knew it would not be completed in time to be
implemented by January of 2006.
The Energy Act anticipated this possibility and specified a default
standard applicable for just 2006. The default standard specified that
the percentage of renewable fuel in gasoline sold or dispensed to
consumers in the U.S. in calendar year 2006 must be 2.78 volume
percent.\1\ The default standard would be applicable if the Agency did
not promulgate regulations to implement the full RFS program for 2006.
Since the full program could not be promulgated during 2006, the
default standard of 2.78 percent applies to calendar year 2006.
However, the provision for the default standard in the Act does not
provide adequate specificity on how to implement the default standard.
For instance, the Act's default standard provision does not specify the
liable parties and the specific nature of their obligation. It also
does not discuss compliance mechanisms, reporting requirements, or
credit generation and use. The resulting uncertainty associated with
the default standard would have created confusion and risked a
problematic initial implementation of the RFS program.
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\1\ The default standard of 2.78 percent represented
approximately 4.0 billion gallons of renewable fuel.
---------------------------------------------------------------------------
As a result, the Agency published a rule on December 30, 2005 that
interpreted and implemented the default provision, to provide certainty
to parties involved in the production and distribution of gasoline and
renewable fuels.\2\ In that action, the Agency clarified the default
standard for 2006 with regulations identifying the liable parties as
refiners, importers, and blenders. The default standard was interpreted
as establishing a collective obligation, rather than an individual
obligation. Under this interpretation, refiners, blenders, and
importers are responsible as a group for meeting the default 2.78
percent standard, and compliance with this standard is calculated over
the pool of all gasoline sold to consumers. An individual refiner,
blender, or importer is not responsible for meeting the 2.78 percent
standard for the specific gasoline it produces. The regulations
implementing the default standard for 2006 did not include any
provisions for credit generation or trading, given the collective
nature of the obligation. However, any shortfall in renewable fuel
production in 2006 would be added as a deficit carryover to the
standard for 2007. Based on information available to date, this does
not appear to be necessary. Total ethanol production in the U.S.
exceeded 4.0 billion gallons in 2005 by a small margin, and several
hundred million gallons of additional ethanol production capacity has
come online in 2006. Thus it is anticipated that the total ethanol
production volume and ultimate use in 2006 will be more than sufficient
to meet the default standard of 2.78 percent.
Today's proposal outlines the full RFS program, covering all of the
provisions required in the Act. It applies in calendar year 2007 and
beyond, since the direct final rule described above addresses RFS
compliance for 2006 only.
---------------------------------------------------------------------------
\2\ 70 FR 77325 (December 30, 2005).
---------------------------------------------------------------------------
D. Development of the Proposal
The RFS program was prescribed in section 1501 of the Act,
including the
[[Page 55557]]
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 program. As with many legislative
actions, various aspects of the program require additional development
by the Agency beyond the specifications in the Act. The credit trading
program and related compliance mechanisms are a central aspect of the
program, and the Agency is responsible for developing regulations to
ensure the successful implementation of the RFS program, based on the
framework spelled out in the statute.
Under the RFS program the credit trading provisions will comprise a
critical element of compliance. Many obligated parties do not have easy
access to renewable fuels or the ability to blend them, and so will
rely on the use of credits to comply. The RFS credit 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.
Given these considerations, 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 in the end 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 finally that the Agency should have the ability to
easily verify compliance to ensure that the volume obligations are in
fact met. Over the course of several months, these guiding principles
helped to move us toward today's proposal.
II. Overview of the Proposal
Today's action describes our proposed requirements for the RFS
program, as well as a preliminary 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 proposal and renewable
fuel impacts assessment. Sections III through V provide the details of
the proposed structure of the program, while Sections VI through X
describe our preliminary assessment of the impacts on emissions, air
quality, fossil fuel use, and cost resulting from expanded renewable
fuel use.
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 program. 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. This makes an assessment of the program of
limited if any utility, given that it is not currently driving real
world impacts and future projections by the Energy Information
Administration indicate that this favorable condition will continue.
Consequently, it is of greater relevance and interest 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 of
the RFS program itself.
In summary, depending on the volume of renewable fuel assumed to be
used in 2012 (7.5 to 9.9 billion gallons), we estimate that this
transition to renewable fuels will reduce petroleum consumption by 2.3
to 3.9 billion gallons or approximately 1.0 to 1.6 percent of the
petroleum that would otherwise be used by the transportation sector.
Carbon monoxide emissions from gasoline powered vehicles and equipment
will be reduced by 1.3 to 3.6 percent while emissions of benzene (a
mobile source air toxic) will be reduced by 1.7 to 6.2 percent. At the
same time, other emissions may increase. Nationwide, we estimate
between a 28,000 and 97,000 ton increase in VOC + NOX
emissions. However, the effects will vary significantly by region with
some major areas like New York City, Chicago and Los Angeles
experiencing no increase while other areas may see an increase in VOC
emissions from 3 to 5 percent and an increase in NOX
emissions from 4 to 6 percent from gasoline powered vehicles and
equipment. Furthermore, the use of renewable fuel will reduce
CO2 equivalent greenhouse gas emissions by 9 to 14 million
tons, about 0.4 to 0.6 percent of the anticipated greenhouse gas
emissions from the transportation sector in the United States in 2012.
On average, we estimate the cost of this increase in renewable fuel to
range from 0.3 cents per gallon to 1 cent per gallon of gasoline for
the nation as a whole. We anticipate additional impacts that we intend
to evaluate as part of the final rulemaking, including changes in
renewable fuel feedstock market prices, decreased imports of petroleum,
and effects on energy security.
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 production data, and fuel quality
data was 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 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 appropriate.
We evaluated the impacts of expanded renewable 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. We also evaluated the impacts on emissions, including
greenhouse gas emissions, and the corresponding impacts on nationwide
and regional air quality. Our preliminary analyses are summarized in
this section. There are a number of uncertainties associated with this
preliminary assessment. The analyses described here will be updated for
the final rule including additional investigation into these
uncertainties.
[[Page 55558]]
1. Renewable Fuel Volumes 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, EIA projects renewable demand in 2012 of 9.6 billion
gallons for ethanol, and 300 million gallons for biodiesel using crude
oil prices forecast at $47 per barrel. Therefore, in assessing the
impacts of expanded use of renewable fuels, we evaluated two
comparative scenarios, one representing the statutorily required
minimum, and one 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.
The Act also stipulates that at least 250 million gallons out of
the total volume required in 2013 and beyond must be cellulosic biomass
ethanol. Because we anticipate a ramp-up in production of cellulosic
biomass ethanol products in the coming years, we have assumed that 250
million gallons of ethanol in 2012 will come from a cellulosic biomass
source. Also, EIA has projected in their economic modeling a biodiesel
demand in 2012 of 300 million gallons. Thus for both the required and
projected volume scenarios that we evaluated for 2012, we assumed these
same production volumes for cellulosic biomass ethanol and biodiesel.
As discussed above, we chose 2004 as our baseline. However, a
direct comparison of the fuel quality impacts on emissions and air
quality required that changes in overall fuel volume, fleet
characterization, and other factors be constant. Therefore, we
developed a reference case which represents the fuel volume, fleet
characterization, and other factors expected in 2012. Fuel quality was
maintained by simply growing ethanol use in equal proportion to growth
in gasoline demand through 2012.
A summary of the assumed renewable fuel volumes for the scenarios
we compared is shown in Table II.A.1-1.
Table II.A.1.-1--Renewable Fuel Volume Scenarios
[billion gallons]
----------------------------------------------------------------------------------------------------------------
2012
-----------------------------------------
2004 Base RFS
case Reference required Projected
case volume volume
----------------------------------------------------------------------------------------------------------------
Corn-ethanol............................................ 3.5 3.9 6.95 9.35
Cellulosic ethanol...................................... 0 0 0.25 0.25
Biodiesel............................................... 0.025 0.028 0.3 0.3
-------------------------------------------------------
Total volume........................................ 3.025 3.928 7.5 9.9
----------------------------------------------------------------------------------------------------------------
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 2012 reference
case. For the nation as a whole, we estimated that summertime VOC and
NOX emissions from gasoline and diesel vehicles and
equipment would each increase by about 0.5 percent for the 7.5 billion
gallon scenario, and by about 1.0 percent for the 9.9 billion gallon
scenario. This would be equivalent to between 28,000 and 97,000 tons of
VOC + NOX nationwide. However, the effects will vary by
region. For instance, for areas in which 10 percent ethanol blends
already predominated in 2004, such as New York City, Chicago, and Los
Angeles, if they continue to use ethanol at the same levels there will
be no impact. However, for conventional gasoline areas in which no
ethanol was used in 2004 but which are projected to transition to full
use of ethanol in 2012, we estimated that VOC and NOX
emissions from gasoline vehicles and equipment would increase by 3-5
percent and 4-6 percent, respectively.
Unlike VOC and NOX, emissions of CO and benzene from
gasoline and diesel vehicles and equipment were estimated to decrease
when the use of renewable fuels increased. Reductions in emissions of
CO varied from as low as 1.3 percent to as high as 3.6 percent for the
nation as a whole, depending on both the renewable fuel volume scenario
and assumptions regarding the amount of ethanol used in reformulated
versus conventional gasoline. Benzene emissions from gasoline vehicles
and equipment were estimated to be reduced from 1.7 to 6.2 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, but do expect a net reduction in ambient PM
levels to result due to the secondary PM impacts as discussed in
section VIII.C. However, data on direct PM emission impacts is
available for biodiesel. We estimate that reductions in emissions of
direct PM from the projected increase in the use of biodiesel to be
about 100 tons nationwide, equivalent to less than 0.5 percent of the
diesel PM inventory.
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. \3\ 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 in 2008 and 2009, and into a subsequent rule to set the
RFS program standard for 2013 and later.
---------------------------------------------------------------------------
\3\ 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 increased use of ethanol on ozone levels for the 7.5 billion
gallon use scenario representing the required volumes
[[Page 55559]]
under the RFS program. We did not evaluate other renewable fuel volumes
scenarios due to the limited amount of time available for completing
this NPRM. 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, ozone levels increased by 0.06 ppb, which represents less
than 0.1 percent of the standard. Even for areas expected to experience
a significant increase in ethanol use, ozone levels increased by only
0.1-0.2 ppb, less than 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 effects may mitigate these already small
ozone increases. The ozone impacts also do not consider the impact of
increased emissions from ethanol and biodiesel production facilities or
any corresponding decrease in emissions from refineries.
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 draft Regulatory Impact Analysis (DRIA). 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 suggests 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 slightly while NOX
would still 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 expected 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. However, ethanol use may have an
affect on ambient PM levels. Emerging science indicates that aromatic
VOC emissions react in the atmosphere to form PM. Increased ethanol use
is expected to cause a corresponding reduction in the aromatic content
of gasoline, which should reduce aromatic VOC emissions and therefore
potentially also impact atmospheric PM levels. All of these issues will
be the subject of further study and analysis in the future.
3. Economic Impacts
As discussed in more detail in Section X, for the final rule we
also plan to assess a range of economic impacts that could result from
the expanded use of renewable fuels. Due to the time required to
complete these analyses, we only have preliminary data for some of
these impacts available for this proposal.
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 $1.20
per gallon in 2012 (2004 dollars) in the case of the 7.2 billion
gallons per year case and $1.26 per gallon in the case of the 9.6
billion gallon 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
$2.11 per gallon if produced using soy bean oil, and less if using
yellow grease or other relatively low cost or no-cost feedstocks. All
of these fuel production costs are without accounting for tax subsidies
for these renewable fuels.\4\ 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, in some cases even exceeding those
prices.
---------------------------------------------------------------------------
\4\ Tax subsidies were subtracted out of the cost estimates, but
consumer behavior in the absence of these tax subsidies was not
modeled.
---------------------------------------------------------------------------
These renewable feedstocks are then used as blend fuels in gasoline
and diesel. While biodiesel is typically just blended with 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 of the increased use of renewable fuels and their replacement of
MTBE, will range from an estimate of 0.3 cent to 1 cent per gallon of
gasoline.
This fuel cost impact does not consider other societal benefits.
For example, the petroleum-based fuel displaced 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 through reductions in net petroleum imports. In Section IX of this
preamble we estimate the value of the decrease in imported petroleum at
about $3.5 billion in 2012 for the 7.5 billion gallon case and $5.8
billion for the 9.6 billion gallon case, in comparison to our 2012
reference case. Total petroleum import expenditures in 2012 are
projected to be about $698 billion.
The above numbers only assess those impacts of increased production
and use of renewable fuel that we can quantify at this time. 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
analyze the impacts on the U.S. agricultural sector, EPA has selected
the Forest and Agricultural Sector Optimization Model (FASOM) developed
by Professor Bruce McCarl, 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
will be focusing upon the agriculture portion of the model.) The
strength of this model is its consideration of the full direct and
indirect impacts of a shift in production of an agricultural commodity.
For example, increased ethanol use will increase the demand for corn.
The model assesses not only the impacts of increased demand for corn on
acres devoted to corn production but also where the incremental corn
will be produced, what other crops will be displaced and how corn is
allocated among competing uses. Shifts in corn production will likely
impact the price of corn and other crop prices. The model can also
estimate the impacts of increased renewable fuel use on animal feed
costs, animal production, costs to consumers and U.S. agricultural
exports. Similarly, FASOM can estimate effects on U.S. farm employment
and income (broken down by region, and farm sector such as corn farmers
versus soybean producers versus the livestock industry, for example).
[[Page 55560]]
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
potential disruption in supply or spike in cost of a particular energy
source is reduced. As part of the RFS rulemaking, EPA is estimating the
energy security effects of reduced oil use due to the expanded use of
renewable fuel. However, these analyses will not be available until the
final rule.
4. Greenhouse Gases and Fossil Fuel Consumption
There has been considerable interest in the impacts of fuel
programs on greenhouse gases and fossil fuel consumption. Therefore, in
this proposed 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
major 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.
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. Based on
a comparison to the 2004 base fuel, we estimated that the increased use
of renewable fuels will reduce petroleum consumption by about 1.0 to
1.6 percent in the transportation sector in 2012. This is equivalent to
2.3-3.9 billion gallons of petroleum in 2012. We also estimated that
greenhouse gases from the transportation sector will be reduced by
about 0.4-0.6 percent, equivalent to about 9-14 million tons. These
reductions are projected to continue to increase in the future as crude
oil prices are expected to continue to provide the stimulus for greater
use of renewable fuels beyond 2012. These greenhouse gas emission
reductions are also dominated by the forecast that the majority of the
future ethanol use will be produced from corn. If advances in
cellulosic technology allow its use to exceed the levels assumed in our
analysis, then even greater greenhouse gas reductions would result.\5\
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\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. Potential Water Quality Impacts
Expansion in the use of renewable fuels will also have other
important impacts which should be the focus of further study and
evaluation. In particular, renewable fuels such as ethanol and
biodiesel produced from agricultural feedstocks raise important issues
with respect to the water quality impacts resulting from the increased
production of corn and soybeans. Due to competing demand, which
includes livestock producers, sweetener manufacturers, and foreign
buyers among others, it is extremely unlikely that the current corn
crop would be devoted to ethanol production. USDA's Economic Research
Service predicts that current demand for feed and exports are expected
to stay constant or perhaps rise.\6\ Additional corn-based ethanol
production would have to come from increased corn yields, increased
acreage, and switching acreage to corn production from other crops like
soybeans and cotton.\7\
---------------------------------------------------------------------------
\6\ ``USDA Agricultural Baseline Projections To 2015,'' February
2006, Economic Research Service.
\7\ For more discussion of agricultural sector effects, see
Section IX.
---------------------------------------------------------------------------
Changes in agriculture as a result of increased use of renewable
fuels can have significant adverse effects upon water quality, either
locally or on a more broad basis. This has the potential to lead to
increased runoff and delivery to water bodies of nutrients, pesticides
and sediments, as well as increased salinity of farmland resulting from
increased irrigation. The increased runoff of nutrients in turn can
cause eutrophication of small water bodies as a result of localized
runoff or large water bodies as a result of increased regional runoff
such as currently occurs in the creation of the hypoxic zone in the
Gulf of Mexico, or eutrophication in the Chesapeake Bay. Some lands
have been retired (e.g., under the Farm Bill's Conservation Reserve
Program, or simply at the land-owner's initiative) because those lands
are highly erosive, steep, or adjacent to water bodies. Therefore,
farming these lands without appropriate mitigation measures would pose
a particularly great risk to water quality and threaten to erase some
of the gains of the last 20 years of Farm Bill and Clean Water Act
implementation. Note that there may be similar environmental
implications in other countries depending on the extent that either
imports of renewable fuels or exports of agricultural commodities such
as corn are affected.
We have not conducted an analysis for this proposal of the impacts
on water quality that might result from the increased use of renewable
fuels. However, this impact could present important public policy
issues as renewable use expands, with examination required of both the
possible benefits and detriments.
B. Program Structure
The RFS program proposed today requires refiners, importers, and
blenders (other than oxygenate blenders) to show that a required volume
of renewable fuel is used. 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
to every batch of renewable fuel produced. The RIN shows that a certain
volume of renewable fuel was produced. 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 in the same manner 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 would both meet the requirements of the Act and provide several
other important advantages:
[[Page 55561]]
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 proposed RIN-based trading program will be 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. The renewable
volume obligation that would apply to an obligated party would 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, since this rulemaking will not be
finalized prior to November, 2006, we are proposing in this notice that
the standard for 2007 be 3.71 percent. Section III.A describes the
calculation of the standard.
2. Who Must Meet the Standard?
Under our proposal, any party that produces gasoline for
consumption in the U.S., including refiners, importers, and blenders
(other than oxygenate blenders), would be subject to a renewable volume
obligation that is based on the renewable fuel standard. These
obligated parties would determine the level of their obligation by
multiplying the percentage standard by their annual gasoline production
volume. The result would 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.
EPA will publish the percentage standard for a year by November of the
preceding year.
For 2007, we are proposing that the renewable fuel volume
obligation be etermined by multiplying the percentage standard by the
volume of gasoline produced or imported prospectively from the
effective date of the final rule until December 31, 2007. As discussed
in Section III.A.3, we considered and are seeking comment on several
other approaches for compliance in 2007, but believe this approach is
most appropriate given the circumstances. We are also confident that
the total volume of renewable fuel used in 2007 will still exceed the
volume specified in the Act.
In determining their annual gasoline production volume, obligated
parties would include all of the finished gasoline which they produced
or imported for use in the contiguous 48 states, and would also include
renewable blendstock for oxygenate blending (RBOB), and conventional
blendstock for oxygenate blending (CBOB). Blenders would count as their
gasoline production only the volumes of blendstocks added to finished
or unfinished gasoline. Renewable fuels blended into gasoline by any
party would not be counted as gasoline for the purposes of calculating
the annual gasoline production volume.
Small refiners and small refineries would be exempt from meeting
the renewable fuel requirements through 2010. All gasoline producers
located in Alaska, Hawaii, and noncontiguous U.S. territories would be
exempt indefinitely. However, if Alaska, Hawaii or a noncontiguous
territory opted into the RFS program, all of the refiners (except for
small refiners and refineries), importers, and blenders located in the
state would be subject tothe 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 proposal flexibly 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 proposed program will provide the
greatest possible encouragement for the development, production, and
use of renewable fuels to reduce our dependence on petroleum. In
general, renewable fuels must be produced from plant or animal products
or wastes, as opposed to fossil fuel sources. Valid renewable fuels
would 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 would qualify. Section III.B
provides more details on the renewable fuels that would be allowed to
be used for compliance with the standard under our proposal.
4. Equivalence Values of Different Renewable Fuels
One question that EPA 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 ethanol be treated as if it were 2.5 gallons of renewable
fuel, but does not specify the values for other renewable fuels. As
discussed in Section III.B.4., we considered and are seeking comment on
a range of options including straight volume, energy content, and life
cycle energy or greenhouse gas emissions. However, we are proposing
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 of 2.5. The
proposed methodology can be used to determine the appropriate
Equivalence Value for any other potential renewable fuel as well.
5. How Will Compliance Be Determined?
Under our proposed program, every gallon of renewable fuel produced
or imported into the U.S. would be assigned a unique renewable
identification number (RIN). A block of RINs could be assigned to any
batch of renewable fuel that is valid for compliance purposes under the
RFS program. These RINs would be placed on product transfer documents
(PTD) as a batch of renewable fuel is 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
could be separated from the batch of renewable fuel to which it had
been assigned, and then either used for compliance purposes or traded.
For excess RINs
[[Page 55562]]
resulting from the production of renewable fuels with Equivalence
Values greater than 1.0, the producer of the renewable fuel could
retain them for marketing separately (they need not be assigned to a
batch of renewable fuel and placed on PTDs).
RINs would represent proof of production which is then taken as
proof of consumption as well, since all 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 potential uses. An
obligated party would demonstrate compliance with the renewable fuel
standard by accumulating sufficient RINs to cover their individual
renewable fuel volume obligation. It would not matter whether the
obligated party used the renewable fuel themselves. A party's
obligation would be to ensure that a certain amount of renewable fuel
was used, whether by themselves or by someone else, and the RIN would
be evidence that this occurred for a certain volume of renewable fuel.
Exporters of renewable fuel would also be required to retire RINs in
sufficient quantities to cover the volume of renewable fuel exported.
RINs claimed for compliance purposes would thus represent renewable
fuel actually consumed as motor vehicle fuel in the U.S.
RINs would be valid for compliance purposes for the calendar year
in which they were generated, or the following calendar year. This
approach to RIN life would be consistent with the Act's prescription
that credits be valid for compliance purposes for 12 months as of the
date of generation. An obligated party could either use RINs to
demonstrate compliance, or could transfer RINs to any other party. If
an obligated party was not able to accumulate sufficient RINs for
compliance in a given year, it could carry a deficit over to the next
year so long as the full deficit and obligation were 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 proposing to place 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
would mean that no more than 20% of the current year obligation could
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 from excess compliance in prior years to
significantly depress renewable fuel demand in any future year. In
keeping with the Act, excess RINs not used would expire.
Section III.D provides more details on how obligated parties would
use RINs for compliance purposes.
6. How Would the Trading Program Work?
Renewable fuel producers and importers would be required to
generate RINs when they produce or import a batch of renewable fuel.
They would then be required to transfer those RINs along with the
renewable fuel batches that they represent whenever they transfer the
batch to another person. Likewise any other party that takes ownership
or custody of the batch would be required to transfer the RIN with the
batch. The RIN could be separated from the batch 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
through blending with conventional gasoline or diesel).
Once a RIN is separated from the batch of renewable fuel that it
represents, it can be used for compliance purposes, banked, or traded
to another party. Separated RINs could be transferred to any party any
number of times. Recordkeeping and reporting requirements would apply
to any party that holds RINs, whether through the ownership or custody
of a batch of renewable fuel or through the transfer of separated RINs.
Thus obligated parties could acquire RINs directly through the
purchase of renewable fuel with assigned RINs, or through the open
market for RINs that would be allowed under this proposal. Section
III.E provides more details on how our proposed RIN trading program
would work.
7. How Would the Program be Enforced?
As in all EPA fuel regulations, there would be a system of
registration, recordkeeping, and reporting requirements for obligated
parties, renewable producers (RIN generators), as well as any parties
that procure or trade RINs either as part of their renewable purchases
or separately. In most cases, the recordkeeping requirements are not
expected to be 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 would be reported and verified. Thus, EPA, as
well as industry could have confidence that invalid RINs are not
generated and that there is no double counting.
C. Voluntary Labeling Program
EPA is considering whether voluntary program options to encourage
adoption and use of practices that minimize environmental concerns
which may arise with the production of renewable fuels are appropriate.
Renewable fuels present a number of environmental advantages as
explained elsewhere in the rulemaking package. However, to assure
maximum advantage we also need to acknowledge the potential adverse
environmental impacts that could arise from the production of renewable
fuel and invite consideration of ways of offsetting these potential
adverse impacts.
While in other areas of this document we focus on general impacts
on air emissions, we also recognize that individual farming and fuel
production operations can contribute to air and water pollution if
appropriate practices and/or controls are not adopted. Increased
production of renewable fuel may result in more intensive use of crop
lands and perhaps the addition of crop land acres to meet the expanding
need for renewable feed stocks. Such trends could have an adverse
impact on, for example, local water quality. Similarly in the case of
fuel production facilities, a range of design and operation options
could result in varying levels of energy use and air and water
pollution.
EPA is considering what voluntary program(s) can be put into place
that would encourage farming and fuel production practices to minimize
concerns that expanded production of renewable fuel in the United
States is likely to result in adverse environmental impacts such as
those identified above.
One option could be a voluntary labeling program which would make
use of the RIN program proposed in this rulemaking. Under this concept,
fuel producers which use best practices would have the option of 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. The details of such a concept, including the points
noted below, would need to be developed before it could be fully
considered for adoption.
[[Page 55563]]
At this time, we are requesting comments on voluntary programs that
would recognize the efforts of farmers and renewable fuel producers
that undertake the most environmentally sound practices and encourage
others to adopt similar practices. In particular we are interested in
comments on options for designs of potential voluntary programs
including what criteria should be used to establish environmentally
sound practices, how to verify that these environmental practices are
indeed used in the production of renewable fuel, how this information
could be used to promote expanded use of good practices, how the
program could be most efficiently and effectively administered whether
by EPA, some other Federal agencies, or perhaps a third-party, and
finally how to assess effectiveness of such a voluntary program.
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 actually 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 how much credit each type of
renewable fuel will receive. This section discusses how the annual
standard is determined and which parties and volumes of gasoline would
be subject to the proposed 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, compliance with the RFS
program requirements will depend heavily on a credit trading program.
This section also describes all the elements of our proposed credit
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 would 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 renewable volume obligation based on this percentage
then the total amount of renewable fuel used is expected to 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,
several adjustments to what is otherwise a simple calculation must be
made.
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 for that year. While the required amount of total renewable fuel
for a given year is provided by the Act, EPA is required 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 would be
further reduced if Alaska, Hawaii, or a U.S. territory chose 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 choose to opt into the RFS
program, the projected gasoline volume would increase above that
consumed in the 48 contiguous states. EIA has 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. Since the October 2006 document
is not currently available for the purpose of proposing the 2007
standard and projecting the 2008 and later standards, we have used the
gasoline volume projections in EIA's 2006 Annual Energy Outlook (AEO),
Table A2 ``Energy Consumption by Sector and Source.'' We intend to use
the October 2006 Short-Term Energy Outlook values for the final rule.
However, these gasoline volumes include renewable fuel use, which
in the coming years is expected to be mostly ethanol. As discussed
below in Section III.C.1, the renewable fuel obligation will 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, the renewable fuel
volume must be subtracted 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 monthly EIA publication Short-
Term Energy Outlook. For the purpose of proposing the 2007 standard and
projecting the 2008 and later standards, we have used the renewable
(ethanol) volume projections in EIA's 2006 Annual Energy Outlook (AEO),
Table 17 ``Renewable Energy Consumption by Sector and Source.'' As for
the gasoline projections discussed above, we intend to use the October
2006 renewable fuel values for the final rule.
The Act exempts small refineries \8\ from the RFS requirements
until the 2011 compliance period. As discussed in Section III.C.3.a,
EPA is proposing to also exempt small refiners \9\ from the RFS
requirements until 2011, and to treat small refiner gasoline volumes
the same as small refinery gasoline volumes. Since small refineries and
small refiners would be exempt from the program until 2011, EPA is
proposing that their gasoline volumes be excluded from the overall non-
renewable gasoline
[[Page 55564]]
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. This would
only occur though the 2010 compliance period when the exemption ends.
Calculation of the standard for calendar year 2011 and beyond would
include small refinery and small refiner volumes.
---------------------------------------------------------------------------
\8\ Under the Act, small refineries are those with 75,000 bbls/
day or less average aggregate daily crude oil throughput.
\9\ 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 previus EPA fuel
regulations.
---------------------------------------------------------------------------
As discussed above, calculation of the standard requires
projections of gasoline use for the upcoming compliance period. EIA
does not project small refinery or small refiner gasoline volumes, so
other methods of estimating these values are necessary. EPA receives
gasoline production data as a part of its fuel programs' reporting
requirements that could be used for this purpose. However, since we do
not receive the data until late February, the most recent complete
annual data set available would be from two years earlier. Given this,
the fact that this adjustment is only needed for 4 years, and because
the total small refinery and small refiner gasoline production volume
is expected to be fairly constant compared to total U.S. gasoline
production during this period, we are proposing to estimate small
refinery and small refiner gasoline volumes using a constant percentage
of national consumption. This percentage would be based on the most
recent small refinery and small refiner gasoline data available in time
for the final rule. Using information from gasoline batch reports
submitted to EPA, EIA data and input from the California Air Resources
Board regarding California small refiners, we have estimated this
percentage to be 13.5%.\10\ EPA requests comments on this method of
estimating small refinery and small refiner gasoline volumes.
---------------------------------------------------------------------------
\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, and thus directionally would reduce the
percentage standard. However, there would be no available data on which
to base such an adjustment. Furthermore, EPA believes that 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) would be very small. In light of the total volume of renewable
fuel required and the precision in which the statute specifies this
total volume, the very small volume at issue here would not change the
resulting percentage. Under the proposal, small refineries and small
refiners are merely treated as any other renewable blender until 2011.
Consequently, whatever renewables they blend will be reflected as RINs
available in the market, and thus should not be accounted for in the
equation used to determine the standard. Therefore, EPA is proposing to
assume this value to be zero.
We are proposing that the amount of renewable fuel used in Alaska,
Hawaii, or U.S. territories would not affect the amount of renewable
fuel required nationwide. We believe this approach is appropriate
because the Act requires that the renewable fuel be consumed in the
contiguous 48 states unless Alaska, Hawaii, or a U.S. territory opt-in.
Additionally, renewable fuel produced in Alaska, Hawaii, and U.S.
territories is unlikely to be transported to the contiguous 48 states,
and vice versa. Thus, 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.
A final issue that could affect the calculated value of the
standard is any deficit carryover from 2006. Any deficit carryover from
2006 would increase the standard only for 2007. Since renewable fuel
use in 2006 is expected to exceed the 2.78 percent default standard, we
are proposing that no deficit be carried 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, in order to get the total projected non-renewable
gasoline volumes from which to calculate the standard, EPA is proposing
to use EIA projections of nationwide and state gasoline consumption,
and small refinery and small refiner volumes estimated as a constant
percentage of national gasoline volumes.
Based on the discussion above, the formula which we are proposing
to be used for calculating the percentage standard is shown below:
[GRAPHIC] [TIFF OMITTED] TP22SE06.000
Where:
RFStdi = Renewable Fuel standard in year i, in percent
RFVi = Nationwide annual volume of renewable fuels
required by section 211(o)(2)(B) of the Act 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)
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)
As described in III.B.4.b, we are not proposing 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 a result, the proposed 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.
EPA is proposing the following formula for calculating the
cellulosic
[[Page 55565]]
standard that is required beginning in 2013:
[GRAPHIC] [TIFF OMITTED] TP22SE06.001
Where, except for RFCelli, the variable descriptions
are as discussed above. The definition of RFCelli is
proposed as:
RFCelli = Renewable Fuel Cellulosic Standard in year i,
in percent
EPA requests comments on the components of both of the proposed
formulas, and on how the values for the components should be obtained.
2. What Are the Applicable Standards?
EPA will set the percentage standard for each upcoming year based
on the most recent EIA 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. We are proposing
the standard for 2007 and estimating the standard for later years based
on current information using the formulas discussed above. The
standards would be 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.
For illustrative purposes, we have estimated the standards for 2007
and later based on current information using the formulas discussed
above.\11\ These values are listed below in Table III.A.2-1. The values
of the variable RFV are the required renewable fuel volumes specified
in the Act (and shown in Table I.B-1). The projected gasoline and
renewable fuels volumes were determined from EIA's energy projections.
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. Small refinery and small refiner gasoline volumes were calculated
based on our proposed method of assuming a constant percentage relative
to projected nationwide gasoline. 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. The deficit for 2006 (applicable to the 2007
standard) was assumed to be zero.
---------------------------------------------------------------------------
\11\ ``Calculation of the Renewable Fuel Standard,'' memo to the
docket from Christine Brunner, ASD, OTAQ, EPA, September 2006.
Table III.A.2-1.--Projected Standards
------------------------------------------------------------------------
Cellulosic
Year Standard standard
------------------------------------------------------------------------
2007............................ 3.71%............. Not applicable.
2008............................ 4.22%............. Not applicable.
2009............................ 4.72%............. Not applicable.
2010............................ 5.21%............. Not applicable.
2011............................ 4.82%............. Not applicable.
2012............................ 4.85%............. Not applicable.
2013+........................... 4.70% min. (non- 0.16% min.
cellulosic).
------------------------------------------------------------------------
For calendar year 2013 and thereafter, the applicable volumes are
to 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. This
rulemaking would present our conclusions regarding the appropriate
applicable volume of renewable fuel for use in calculating the
renewable fuel standard for 2013 and beyond. However, at a minimum we
expect that the sum of the cellulosic and non-cellulosic standards for
2013 will be no lower than the 2012 standard. Until such time as we
conduct that rulemaking, the program proposed by this rule would
continue to apply after 2012.
Prior to 2013, the Act specifies that cellulosic biomass ethanol or
waste derived ethanol will be considered equivalent to 2.5 gallons of
renewable fuel when determining compliance with the renewable volume
obligation. As discussed in Section III.D below, a batch's RIN would
indicate whether it was cellulosic or non-cellulosic ethanol. Beginning
in 2013, the 2.5 to 1 ratio no longer applies for cellulosic biomass
ethanol. In its place, 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 above, we have estimated this value (250 million
gallons) as a percent of an obligated party's production for 2013.
Thus, an obligated party would be subject to two standards in 2013 and
beyond, a non-cellulosic standard and a cellulosic 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. As
described in Section I.C, 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. However, the Act
provides no default standard for any other year. Instead, the
regulations we promulgate are required to address renewable fuel usage,
including calendar year 2007. The program we are proposing today will
therefore apply in 2007. While we plan to promulgate the final rule as
soon after today's proposal as possible, it will likely not be
effective by January 1, 2007. Therefore, our proposal must address how,
and for what time periods, the applicable standard and other program
requirements will apply to regulated parties for gasoline produced
during 2007.
We have identified several options for 2007 compliance. One option
would be to extend the collective compliance approach used for 2006 to
2007. Although the Act contains no default
[[Page 55566]]
standard applicable to 2007, under this approach we would apply the
renewable fuel standard that we calculate for 2007 to obligated parties
on a collective basis rather than on an individual basis. Under this
approach, no individual facility or company would be liable for meeting
the applicable standard. At the end of 2007 we would determine if the
industry as a whole had met the standard on average, and any deficit
would be carried over into 2008. This approach would be essentially
equivalent to deferring the start of the program to 2008, but with the
addition of an industry-wide deficit carryover provision. Current
projections from the Energy Information Administration (EIA) on the
volume of renewable fuel expected to be produced in 2007 indicate that
an industry-wide deficit carryover would most likely be unnecessary
under this collective compliance approach.
However, given the requirements of the Act, we do not believe that
a collective compliance approach is appropriate for 2007. The Energy
Act requires us to promulgate regulations that provide for the
generation of credits by any person who overcomplies 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.
A variation of the collective compliance approach would add a
credit carryover provision in which any excess renewable fuel produced
on an industry-wide basis in 2007 would be subtracted from the required
volume in the calculation of the applicable 2008 standard. However,
under a collective compliance approach, such a credit carryover
provision would not meet the statutory requirement since no individual
companies could generate, bank, or trade credits. Therefore we do not
believe that a collective compliance approach is appropriate.
Another option for 2007 compliance would be for obligated parties
to calculate their renewable fuel obligation based on all gasoline
volumes produced at any time during the calendar year, regardless of
when in 2007 the final rule is published or becomes effective (i.e.,
the calculation of the renewable volume obligation looks back
retroactively to the beginning of the year for gasoline production).
Compliance would be determined based on a whole calendar year's
production of gasoline, and the compliance determination would not be
required until calendar year 2007 was over, after the final rule was
published. Obligated parties would know the proposed standard based on
today's action, and all regulated parties would likewise know the
proposed provisions for recordkeeping, RIN generation and assignment,
etc. On this basis they could begin the process of generating RINs and
tracking batches of renewable fuel prior to the publication of the
final rule. However, it might not be appropriate to apply the standard
to all gasoline produced in 2007 unless the regulatory provisions in
today's proposal are very similar to those in the final rule.
Otherwise, obligated parties and renewable fuel producers would not
have adequate lead-time.
For this approach to be effective, renewable producers would have
to begin placing RINs on their PTDs at the start of the year 2007 even
though the regulations are not yet final. If they do not, then there
could be a shortage of RINs available for obligated parties to use for
compliance by the end of the year. Since there is no guarantee that
renewable fuel producers would generate RINs appropriate prior to
adoption of the regulations, another option would be for the Agency to
finalize just those RIN-related provisions prior to the end of 2006
that are critical to measuring and tracking batches of renewable fuel
and the assignment of RINs to those batches. However, in practice this
approach would be little different than finalizing the full rulemaking.
As a result we do not believe that this would be a viable option given
the time available.
Finally, given the challenges and shortcomings inherent in the
other options, we could simply apply the renewable fuel standard 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. As a
result, such an approach would be relatively straightforward to
implement, provide the industry with the certainty they need to comply,
and give them time to put in place their compliance plans and actions.
It also would be unlikely to have any negative impacts on renewable
fuel use given the expectations that total volumes in 2007 will exceed
the national volume required for 2007. This is the approach we are
proposing today.
This ``prospective'' approach would not formally apply the standard
to all of the gasoline produced in the 2007 calendar year. As a result,
it would not formally ensure that the total volume of renewable fuel
required to be used in 2007 would actually be used. However, given the
present circumstances, we believe this is an appropriate way to
implement the Act's provisions. We are confident that the combined
effect of the proposed regulatory 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.
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.\12\ Under this option we believe there would
be reasonable lead-time for regulated parties to meet their 2007
compliance obligations.
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\12\ 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 promulgate regulations.
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While we are proposing to apply the renewable fuel standard for
2007 prospectively only from the effective date of the final rule, we
nevertheless request comment on all these options for addressing
compliance in calendar year 2007.
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
[[Page 55567]]
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 would likewise be reduced proportionally and
their ability to comply with the RFS requirements would 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.\13\ 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. 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.
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\13\ 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 aklyl ester) and renewable diesel (other diesels that
meet the Energy Act's definition but are not mono akly esters.
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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 intends to consider 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 vehicles, without
regard to whether it in fact is used in a highway or nonroad vehicle.
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
an RVO without the need to track it to determine its actual application
in a highway vehicle. 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. Fuels that otherwise meet this
definition but are designated by the producer for use in boilers, or
heaters, or any use other than highway or nonroad use, would not meet
the definition of renewable fuel.
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 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. 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 ``biocrude,'' 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, other fuels that meet
the definition of renewable fuel include biodiesel and various
alternative fuels that can be used in their neat form, such as ethanol,
methanol or natural gas, without blending into gasoline and without
being used to produce a gasoline blending component (such as ETBE). The
definition of renewable fuel in the Act is not limited to fuels that
can be blended with gasoline. 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, in the
billions of gallons 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 bio-diesel,
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
[[Page 55568]]
renewable fuel obligation would still be ethanol blended with gasoline.
Whether one counts or does not count these additional renewable fuels
would not in practice change whether the total national goal for
renewable fuel use was met, given the size of the goal specified in the
Act and the form in which the total is expressed. 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 would avoid 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 EPA believes its
proposal is consistent with the intent of Congress and is a reasonable
interpretation of the Act.
We are therefore proposing that in addition to any renewable fuels
that are actually blended into gasoline and are designated for use in a
highway vehicle, we would also count any renewable fuels falling into
the following categories as being valid for RFS compliance purposes:
1. Any renewable fuels used in nonroad applications;
2. Any renewable fuels used in their neat (unblended) form in
onroad and nonroad applications; and
3. Any renewable fuel used in a motor vehicle that does not
normally run on gasoline. For instance, biogas used in a CNG vehicle,
or biogenic methanol used in a dedicated methanol vehicle.
The Agency solicits comment on this approach.
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, but can also
be produced from carbohydrates in corn and other feedstocks. This
process is accomplished by first converting the carbohydrates 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 carbohydrates to make ethanol. Cellulosic feedstocks
(composed of cellulose and hemicellulose) are currently more difficult
and costly to convert to sugar than are carbohydrates because of this
intermediate conversion step. While the cost and difficulty are a
disadvantage, the cellulosic process offers the advantage that more
feedstocks can be used and 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 While these materials may or may not contain
cellulosic material, their inclusion in the definition requires that
ethanol made from such sources be treated as cellulosic biomass ethanol
under the regulations. ``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.''
b. Ethanol Made From Any Feedstock in Facilities Run Mostly With
Biomass-Based Fuel. 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 proposes to interpret 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 propose to interpret as meaning (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, 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, could be used as
fuel for gasifier/boiler units at ethanol plants, since they are waste
materials and would not be used as a feedstock to carbohydrate-based
ethanol plants. Although such waste materials conceivably could be
feedstocks to a cellulosic ethanol plant, its use as a fuel at a
carbohydrate based ethanol plant does not subvert the intent of the
definition.\14\
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\14\ On the other hand, wood from plants or trees that are grown
as anenergy 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.
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[[Page 55569]]
Today's regulations will require owners of ethanol plants to keep
records of fuel use to ensure compliance with and enforcement of this
provision of the definition of cellulosic ethanol. Due to potential
enforcement-related problems associated with application of this
component of the definition of cellulosic ethanol to foreign
facilities, we intend for the final rule to develop compliance and
enforcement related safeguards similar to those set forth in proposed
80.1165(f), (g), (h) and (j), and with additional inspection, audit,
recordkeeping and reporting safeguards to verify compliance with the
requirements on fuel use at foreign facilities. We seek comment on the
most effective means of doing this. Because of the difficulty of
implementing these safeguards, however, we also solicit comment on a
provision that would limit the application of this definition of
cellulosic ethanol only to ethanol plants in the U.S.
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
are proposing to include waste heat in the definition of ``other waste
materials'', and also that waste heat captured and used as a source of
thermal energy in an ethanol plant would satisfy the requirement of
other waste materials being ``otherwise used'' to make ethanol.
Although the source of the waste heat is ultimately a fossil fuel in
most cases, we recognize that without the capture of the heat and
subsequent use in the ethanol plant, that energy would be unused, and
the ethanol plant would consume the equivalent amount of fossil fuel.
Thus, for the same amount of fossil fuel consumption at the off-site
plant, heat energy capture would result in displacement of fossil fuel
use at the ethanol plant. Because of potential confusion identifying
thermal energy that is waste heat from fossil fuel combustion sources
on site (i.e., at the ethanol plant itself), we are limiting this
proposal to waste heat captured at off-site plants. The Agency solicits
comment on our proposal to consider waste heat in the definition of
``other waste materials''.
We propose to interpret the term ``fossil fuel normally used in the
production of ethanol'' to mean 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 criteria 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.\15\ The
Agency solicits comments on this aspect of our approach in accounting
for fossil fuel displacement.
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\15\ 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 plant in our analysis, we are using
average nationwide values, rather than data collected for individual
plants.
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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 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. We are therefore
proposing that the displacement of 90 percent of fossil fuels at the
ethanol plant means those fuels consumed on-site and that are used to
generate thermal energy used to produce ethanol. The term ``fossil fuel
normally used in the production of ethanol'' in today's proposal means
fossil fuel that is combusted at the facility itself to produce thermal
energy. Owners are required 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 the
waste heat captured and used in the ethanol 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 would 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. Holders of RINs associated with the
sale or trade of such cellulosic ethanol would get the benefit of the
2.5 credit (through 2012 when such credit is valid).
In the event that the requirements of 90 percent displacement of
fossil fuel are not met, the owner of a facility producing such ethanol
would be required to obtain additional RINs to make up whatever deficit
exists for those RINs sold or traded with a value of 2.5. Assuming this
is made up, then holders of the RINs associated with the ethanol the
plant produced in the previous year would not be affected. We solicit
comment on this proposed approach.
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.'' The determination of the appropriate category of
ethanol is based on whether the feedstocks on question contain
cellulose or hemicellulose that is used to make the ethanol. Thus, if
the ethanol is made from the non-cellulosic portions of animal, other
waste, or municipal waste, it is labeled ``waste derived ethanol.''
2. What Is Biodiesel?
The definition of renewable fuel in the Act includes corn-based and
cellulosic biomass ethanol, waste derived ethanol, and the renewable
fuel portion of blending components derived from renewable fuel.
Biodiesel is also specifically named as being included in the Act's
definition of renewable fuel. 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 ASTM specification D-6751 \16\ (the most common meaning of
the term
[[Page 55570]]
``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.
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\16\ In the event that the ASTM specification D-6751 is
succeeded with a different number in the future, EPA may revise the
regulations accordingly at such time.
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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 propose to divide 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 would fulfill the Act's definition of biodiesel. The
Agency solicits comment on this approach and specifically asks whether
the ``non-ester renewable diesel'' definition be referenced explicitly
to ASTM D-975.
a. Biodiesel (Mono-Alkyl Esters). Under this part, 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-6751-02a; (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
including, but not limited to, 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.
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 including, but not limited to, 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. Current examples of a non-ester renewable
diesel include: ``renewable diesel'' produced by the Neste process, or
diesel fuel produced by processing fats and oils through a refinery
hydrotreating process.
3. Is Motor Fuel That Is Made From a Renewable Feedstock a Renewable
Fuel?
We interpret the statutory definition of renewable fuels to include
all gasoline or diesel that is made from a class of feedstocks called
``biocrudes'', which are defined as biologically derived feedstocks
(such as fats and greases). We are providing a definition of
``biocrude-based renewable fuels'' to mean gasoline or diesel products
resulting from the processing of biocrudes in production units within
refineries that process crude oil and other petroleum based feedstocks
and which make gasoline and diesel fuel.\17\ A particular batch of
biocrude 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 non-ester renewable diesel defined
in Section III.B.2.b above could be one such type.
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\17\ Biocrude-based renewable fuels will need to be registered
under the provisions contained in 40 CFR 79 Part 4 before they can
be sold commercially.
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We are assuming that all of the biocrude used as a feedstock in a
refinery unit will end up as a biocrude-based renewable 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 proposing to have the volume of the biocrude 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.
We are also proposing that the Equivalence Value assigned to
biocrude-based renewable fuels be designated as 1.0, despite the fact
that they might warrant a higher value based on their energy content as
described in the next section.\18\ This approach should balance out the
likelihood that some of the biocrude-based renewable fuel is not a
motor vehicle fuel.
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\18\ With respect to biodiesel, however, since such fuel is
typically not made in a traditional petroleum-based refinery, it
would not be a biocrude-based renewable fuel and would thus not be
limited to the 1.0 Equivalence Value.
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4. What Are ``Equivalence Values'' for Renewable Fuel?
One question that EPA must address is how to count volumes of
renewable fuel in determining compliance with the renewable volume
obligation. For instance, the Act stipulates that every gallon of
cellulosic 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 proposing that the ``Equivalence Values'' for 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,
and for cellulosic ethanol of 2.5. However, the methodology can be used
to determine the appropriate equivalence value for any other potential
renewable fuel as well.
This section describes why we believe that the use of relative
energy content is appropriate under the Act, and our investigation of
the alternative use of lifecycle analyses as the basis of Equivalence
Values.
a. Authority Under The Act To Establish Equivalence Values. We are
proposing 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 would mean that every physical gallon of
renewable fuel would count as one gallon for RFS compliance purposes.
An Equivalence Value greater than 1.0 would mean that every physical
gallon of renewable fuel would count as more than one gallon for RFS
compliance purposes, while a value less than 1.0 would count as less
than one gallon.
We are interpreting the Act as allowing EPA to develop Equivalence
Values according to the methodology discussed below. We believe that
the use of Equivalence Values is consistent with the intent of Congress
to treat different renewable fuels differently in different
circumstances, and to provide
[[Page 55571]]
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. All of 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 for certain specified circumstances.
The Act is unclear as to whether a straight gallon measurement is
required in circumstances other than those specified by Congress. We
believe the Act can and should be interpreted to allow the use of
Equivalence Values in those circumstances. First, this is consistent
with the way Congress treated the various specific circumstances noted
above, and thus is basically a continuation of that process. Second,
EPA does not believe that providing such an Equivalence Value for this
small volume of renewable fuel will interfere in any way with meeting
the total national volume goals for usage of renewable fuel. We are
proposing to use an Equivalence Value of 1.0 for ethanol other than
cellulosic biomass or waste derived ethanol, and we expect that there
will only be very limited additional situations where an Equivalence
Value other than 1.0 is used. As a result, this approach is a
reasonable way for the RFS program to ensure that the total volume of
renewable fuels will be used as required under the Act.
b. Energy Content and Renewable Content as the Basis for
Equivalence Values. We believe it is appropriate to base the
Equivalence Value assigned to a particular renewable fuel on the degree
to which the renewable fuel supplants the petroleum content of fuel
used in a motor vehicle. This is consistent with the Act's definition
of renewable fuel, which refers to the degree to which it is directly
used to replace or reduce the quantity of fossil fuel present in a fuel
mixture used to operate a motor vehicle. The degree to which the fossil
fuel is replaced is best represented by its relative energy content. 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 propose to calculate Equivalence
Values using both the renewable content of a renewable fuel and its
energy content. This section describes our proposal for calculating the
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 would be 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 could be 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 would allow actual volumes of
renewable fuel to be consistent with the volumes required by the Act
while still allowing some renewable fuels to be attributed a higher
value in terms of RFS compliance to the extent that they have a higher
energy content than ethanol.
Equivalence Values should 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. We have interpreted this to
mean that every renewable fuel should be evaluated at the molecular
level to distinguish between those components that were derived from a
renewable feedstock, versus those components that were derived from a
fossil fuel feedstock. Along with energy content in comparison to
ethanol, the relative amount of renewable versus non-renewable content
can then be used directly as the basis for the Equivalence Value.
We propose that the calculation of Equivalence Values should
simultaneously take into account both the renewable content of a
renewable fuel and its energy content in comparison to ethanol. To
accomplish this, we propose 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.
REth = Renewable content of ethanol, in percent.
ECRF = Energy content of the renewable fuel, in Btu per
gallon (LHV).
ECEth = Energy content of ethanol, in Btu per gallon
(LHV).
R is a measure of that portion of a single renewable fuel molecule
which can be considered to have come from a renewable source. Since R
is being combined with relative energy content in the formula above,
the value of R cannot be based on the weight fraction of the renewable
atoms in the molecule, but rather must be based on the energy content
of those atoms. As a result the calculation of R for any particular
renewable fuel requires an analysis of the chemical process through
which it was produced. A detailed explanation of calculations for R and
several examples are given in a technical memorandum in the docket
\19\.
---------------------------------------------------------------------------
\19\ ``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 its 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. In general this would mean that
the Equivalence Value of ethanol would be 0.95. However, 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
[[Page 55572]]
allow them to include the denaturant in their reported volumes.
Since we are proposing 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 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. We are therefore proposing three
simplifications to streamline the application of Equivalence Values in
the context of the RFS program. First, consistent with our approach to
the R value for ethanol, we are proposing that all Equivalence Values
calculated to be in the range of 0.9-1.2 be treated as if they were
exactly 1.0. This approach would eliminate many of the complexities
described in Section III.D.2 that are associated with using renewable
fuels for RFS compliance purposes that have an Equivalence Value other
than 1.0. Second, we propose that several bins be created for renewable
fuels with Equivalence Values above 1.0. These bins would replace the
calculated Equivalence Values with standardized ones to account for
uncertainty in the calculations as well as to simplify their
application. We propose that the bins be 1.0, 1.3, 1.5, and 1.7. Each
renewable fuel would be assigned to the bin that is closest to its
calculated Equivalence Value. Finally, we propose that all Equivalence
Values, if any, which are calculated to be less than 0.9 be rounded to
the first decimal place.
Using the methodology described above, we calculated the
Equivalence Values for a number of different renewable fuels expected
to be in use over the next few years, and modified them according to
our proposed rounding protocols. These are shown in the table below.
Table III.B.4-1.--Proposed Equivalence Values for Some Renewable Fuels
------------------------------------------------------------------------
Equivalence
Value (EV)
------------------------------------------------------------------------
Cellulosic biomass ethanol or waste-derived ethanol..... 2.5
Ethanol from corn, starches, or sugar................... 1.0
Biodiesel (mono alkyl ester)............................ 1.5
Non-ester renewable diesel.............................. 1.7
Butanol................................................. 1.3
ETBE from corn ethanol.................................. 0.4
------------------------------------------------------------------------
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. In such
cases we propose to allow the producer to submit a petition to the
Agency describing the renewable fuel, its feedstock and production
process, and the calculation of its Equivalence Value. The Agency would
review the petition and assign an appropriate Equivalence Value to the
renewable fuel based on the proposed rounding protocols described
above. Regarding publication of the newly assigned Equivalence Value,
we could publish it in the Federal Register at the same time as the
annual standard is published each November. We request comment on
whether publishing new Equivalence Values in this manner is
appropriate.
Regarding biodiesel (mono alkyl esters), we also considered an
additional approach in setting the Equivalence Value. 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, it might be appropriate to create a parallel
provision for biodiesel made from wastes. Under this approach,
biodiesel made from waste products would be assigned an Equivalence
Value of 2.5 through 2012. Currently, waste products (for example,
poultry fats and poultry wastes, municipal solid waste, or wastewater
sludge) make up less than 10 percent of biodiesel feedstocks. This
approach would have the effect of incentivizing the use of waste
products and recycled biomass to make biodiesel. Beyond the RFS
program, it could also set a precedent to promote recycling and waste
conservation. While we are not proposing to set the Equivalence Value
for waste-derived biodiesel at 2.5 in today's action, we nevertheless
believe that this approach has merit and request comment on it.
c. Lifecycle Analyses as The Basis for Equivalence Values. Although
we are proposing that Equivalence Values be based on energy content
relative to ethanol and renewable content, some stakeholders have
suggested that Equivalence Values should be based on lifecycle
analyses. Such an approach may have merit, but it would also raise a
number of challenges. Consequently, we are inviting comment here not
only on the merit and basis for setting equivalence values on a
lifecycle basis, but also the appropriate means of doing so.
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 they provide a more
complete picture of the potential impacts of different fuels or
different fuel sources.
Advocates for using lifecycle analyses for setting the Equivalence
Values for different renewable fuels indicate that there could be
several advantages to 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 fossil fuel use or emissions.
At the same time, the use of lifecycle analyses to establish the
Equivalence Values for different renewable fuels also raises a number
of issues. For instance, lifecycle analyses can be conducted using
several different metrics, including total fossil fuel consumed,
petroleum energy consumed, criteria pollutant emissions (e.g., VOC,
NOX, PM) carbon dioxide emissions, or greenhouse gas
emissions. Each metric would result in a different Equivalence Value
for the same renewable fuel. At the present time there is no consensus
on which metric would be most appropriate for this purpose.
[[Page 55573]]
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 can vary widely from one
facility or process to another. There currently exists no single body,
governmental or otherwise, that has organized a comprehensive dialogue
among stakeholders about the appropriate tools and assumptions behind
any lifecycle analyses with the goal of coming to agreement.
Another issue 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, criteria 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 unless the RFS standard was
simultaneously adjusted.
Finally, lifecycle analyses of different renewable fuels are likely
to change over time as farming practices and process technologies
evolve. Significant changes would necessitate corresponding changes in
the RFS program to adjust the Equivalence Values on an ongoing basis
which would add uncertainty into the long-term RIN market.
We request comment on all issues associated with the use of
lifecycle analyses in establishing the Equivalence Values for different
renewable fuels for the RFS program.
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.\20\ To implement this provision, we are
proposing that the volume of gasoline used to determined the renewable
fuel obligation include all finished gasoline, RFG and conventional,
produced or imported for use in the contiguous United States during the
annual averaging period. We are also proposing to include in the volume
of gasoline used to determine the renewable fuel obligation 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 (e.g. sub-octane conventional
gasoline), called ``CBOB.''
---------------------------------------------------------------------------
\20\ CAA Section 211(o)(2)(A)(i), as added by Section 1501(a) of
the Energy Policy Act of 2005.
---------------------------------------------------------------------------
Under the proposed rule, the volume of any other unfinished
gasoline or blendstock, such as butane, would not be 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. Where a blendstock is blended with other
blendstock to produce finished gasoline, RBOB, or CBOB, the total
volume of the gasoline blend would be included in the volume used to
determine the renewable fuels obligation for the blender. Where a
blendstock is added to finished gasoline, only the volume of the
blendstock would be included, since the finished gasoline would have
been included in the compliance determinations of the refiner or
importer of the gasoline.\21\ Gasoline produced or imported for use in
a noncontiguous state or U.S. territory \22\ would not be included in
the volume used to determine the renewable fuels obligation (unless the
noncontiguous state or territory has opted-in to the RFS program), nor
would gasoline, RBOB or CBOB exported for use outside the United
States.
---------------------------------------------------------------------------
\21\ ``Gasoline treated as blendstock,'' or ``GTAB,'' would be
treated as any other blendstock with regard to the RFS rule; i.e.,
where the GTAB is blended with other blendstock to produce gasoline,
the total volume of the gasoline blend, including the GTAB, would be
included in the volume gasoline used to determine the renewable fuel
obligation for the blender. Where the GTAB is blended with finished
gasoline, only the GTAB volume would be included.
\22\ 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 we are proposing to include in the volume of
gasoline used to determine the renewable fuel obligation are
collectively called ``gasoline.''
Generally, ethanol and other renewable fuels would typically be
used in gasoline, increasing the volume of the entire gasoline blend.
We are proposing to exclude 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 is 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.''
\23\ 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 would apply to any renewable fuels that are
blended into gasoline at a refinery, contained in imported gasoline, or
added at a downstream blending facility. 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
[[Page 55574]]
volume of renewable fuels required, merely on the number of obligated
parties. We invite comment on the proposal to exclude renewable fuels
in the volume of gasoline subject to the renewable fuels obligation. As
discussed earlier, in a similar manner this volume of renewable fuel
would also be excluded from the calculation performed each year by EPA
to determine the applicable percentage.
---------------------------------------------------------------------------
\23\ CAA Section 211(o)(3)(B), as added by Section 1501(a) of
the Energy Policy Act of 2005.
---------------------------------------------------------------------------
2. Who Is Required To Meet the Renewable Fuels Obligation?
Under the proposed rule, persons who meet the definition of
refiner, which includes blenders who produce gasoline by combining
blendstocks or blending blendstocks into finished gasoline, and persons
who meet the definition of importer under the fuels regulations would
be subject to the renewable fuel obligation. As noted above, blenders
who only blend renewable fuels downstream from the refinery or importer
would not be 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, as the covered blenders are all refiners
under the regulations.
A refiner or importer located in a noncontiguous state or U.S.
territory would not be subject to the renewable fuel obligation and
thus would not be an obligated party (unless the noncontiguous state or
territory opts-in to the RFS program). A party located within the
contiguous 48 states that ``imports'' into the 48 states gasoline
produced or imported by a refiner or importer located in a
noncontiguous state or territory would be an obligated party and must
meet the renewable fuel obligation for such gasoline.
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.'' \24\ Under the proposed rule, 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. Beginning in 2011, small refineries would be
required to meet the same renewable fuel obligation as all other
refineries. This exemption would apply 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.
---------------------------------------------------------------------------
\24\ 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 are
proposing to extend this relief to refiners who meet the proposed
criteria for small refiner status. Under the proposal, a small refiner
is defined as any refiner who, during 2004: (1) Produces gasoline at a
refinery by processing crude oil through refinery processing units; (2)
employs 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) has a total crude oil processing capability for all
of the small refiner's refineries of 155,000 barrels per calendar year
(bpcd). These size requirements were established in prior rulemakings
and were the result of our analysis of small refiner impacts. We do not
believe that there are more than 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
request comment on whether a refiner who has a refinery which exceeds
the 75,000 bpcd criteria should be eligible to apply for a small
refiner exemption under the RFS program. EPA believes it has this
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 are also proposing to allow foreign refiners to apply for a
small refinery or small refiner exemption under the RFS program. This
would apply to foreign refiners that apply for refineries under the
75,000 bpcd criteria or foreign refiners that apply for small refiner
status. Under the anti-dumping, MSAT and gasoline sulfur rules, foreign
refiners are allowed to comply with certain regulations separately from
any importer. Additional requirements applicable to such foreign
refiners are included in these rules to ensure that enforcement of the
regulations at the foreign refinery would not be compromised. We are
proposing similar enforcement-related requirements that would apply to
foreign refiners that apply for a small refinery or small refiner
exemption. Under the existing fuels regulations, few foreign refiners
have chosen to undertake these additional requirements, and almost all
gasoline produced at foreign refineries is included in the importers'
compliance determinations. We invite comment on the value of extending
the small refinery and small refiner exemptions to foreign refiners
under the RFS program.
Under the proposed rule, 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. The
application must include documentation that the small refinery's
average aggregate daily crude oil throughput for calendar year 2004 did
not exceed 75,000 barrels. As long as the refinery met the criteria in
2004, it would have the exemption through 2010 regardless of changes in
crude throughput or ownership. A 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 are proposing to base
eligibility 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 Hurricane Katrina in
2005. We request comment on whether multiple-year average should be the
basis for eligibility.
As discussed above, 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. The application must be received by EPA by
September 1, 2007 for the exemption to be effective in 2007 and
subsequent calendar years. Like the exemption for small refineries,
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.
EPA will notify the refiner of approval or disapproval of small refiner
status by letter. Unlike the case for small refineries, refiners that
receive approved small refiner status and subsequently do not meet all
of the criteria for small
[[Page 55575]]
refiner status (i.e., cease producing gasoline from 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. 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, the proposed rule includes a process by which
refiners with small refineries may petition EPA for an extension of the
small refinery exemption. As provided in the Act, the proposed rule
would require EPA to act on the petition not later than 90 days after
the date of receipt of the petition.
During the initial exemption period and any extended exemption
periods, the gasoline produced by small refineries and refineries owned
by approved small refiners would be subject to the renewable fuel
standard.
Under the proposed rule, the automatic five year exemption for
small refineries, and any extended exemptions, may be waived upon
notification to EPA. In waiving its exemption, gasoline produced at a
small refinery would be included in the RFS program and would be
included in the gasoline used to determine a refiner's renewable fuel
obligation. If a refiner waives the exemption for their small refinery
or their exemption as a small refiner, the refiner would 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 refiner operates as an oxygenate
blender).
b. General Hardship Exemption. In recent rulemakings, we have
included a general hardship exemption for parties that could
demonstrate severe economic hardship in complying with the standard. We
are proposing not to include in the RFS program provisions for a
general hardship exemption. 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 would 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 would 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, we believe that there likely would be no need for a
general hardship exemption. We request comment on whether there is a
need to include a general hardship exemption in the RFS program.
c. Temporary Exemption Based On Unforeseen Circumstances. In recent
rulemakings, we have also included a temporary exemption based on
unforeseen circumstances. We are proposing 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 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 believe, therefore,
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 request
comment on whether there would be a need to include a temporary
exemption based on unforeseen circumstances, and, in particular,
circumstances that may affect ethanol producers.
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 effective date of the RFS
program.\25\ 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.
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\25\ CAA Section 211(o)(2)(A)(ii), as added by Section 1501(a)
of the Energy Policy Act of 2005.
---------------------------------------------------------------------------
Today's proposed rule would implement this provision of the Act by
providing a process wherein the governor of a noncontiguous state or
territory may petition EPA to have the state or territory included in
the RFS program. However, we believe that approval of the petition
would not require a showing other than a request to be included in the
program. The petition must be received by EPA on or before October 31
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 October 31 would not be included
in the RFS program in the next calendar year, but would be included in
the RFS program in the following 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 October 31
would be necessary to allow EPA time to make any adjustments in
applicable standard. The method for recalculating 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.
Where a noncontiguous state or territory opts-in to the RFS
program, producers and importers of gasoline for that state or
territory would be obligated parties subject to the renewable fuel
requirements. All refiners, blenders and importers who produce or
import gasoline for use in a state or territory that has opted-in to
the RFS program would be required to count this volume of gasoline in
determining their renewable fuel obligation, and would be able to
separate RINs from batches of renewable fuels used in gasoline that is
sold or introduced into commerce in the
[[Page 55576]]
state or territory that has opted-in to the RFS program.
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 request comment on the opt-in
provisions.
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.\26\ 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.
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\26\ CAA Section 211(o)(7), as added by Section 1501 of the
Energy Policy Act of 2005.
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If EPA 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 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. Renewable fuel
use in the state in question would thus continue to be driven by
natural market forces.
Given that state petitions for a waiver of the RFS program are
unlikely to affect renewable fuel use in that state, we are not
proposing 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. We request comment
on this approach.
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. The Act envisions a
regulatory program that would ensure the national volume is met as long
as a refiner or importer ensured that someone used a certain volume of
renewable fuel, whether it was themselves or another party. 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 proposed compliance program. It is based
on the use of unique renewable identification numbers (RINs) assigned
to batches of renewable fuel by renewable fuel producers. These numbers
could then be sold or traded, and ultimately used by any obligated
party to demonstrate compliance with the applicable standard. Excess
RINs would be identical to the credits envisioned by the Act. 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 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 they 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 can be used only as
motor vehicle fuel. In discussions with stakeholders, it has become
clear that other renewable fuels, including biodiesel and renewable
fuels used in their neat (unblended) form, likewise are not used for
anything other than 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. It is therefore appropriate for EPA to
establish the obligation for refiners and importers as an obligation to
ensure that a certain volume of renewable fuel has been produced. This
will ensure that the total required volume of renewable fuels will be
used in the U.S., and as discussed below has many benefits as far as
streamlining the program and minimizing disruptions to the current
marketplace for production, distribution, and use of renewable fuels.
Implementing a program that is based on ensuring production of a
certain volume of renewable fuels requires a system of volume
accounting and tracking of renewable fuels. We propose that this system
be based on the assignment of unique numbers to each batch of renewable
fuel. These numbers would be called Renewable Identification Numbers or
RINs, and would be assigned to each batch by the renewable fuel
producer or importer.
The use of RINs would allow 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 as described in
Section III.D.1.b below. For instance, ethanol producers are already
required to report their production volumes to EIA through Monthly
Oxygenate Reports. This data would provide an independent source for
verifying volumes. The total number of batches and parties involved is
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 are approximately 100 ethanol plants and 40
biodiesel plants in the U.S., compared with approximately 1200
blenders.\27\
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\27\ Those blenders who add ethanol to RBOB are already
regulated under our reformulated gasoline regulations.
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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
[[Page 55577]]
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 can also identify the Equivalence Value of the
renewable fuel which will often only be known at the point of its
production. Finally, the RIN can identify the year in which the batch
was produced, a critical element of determining the applicable time
period within which RINs are valid for compliance purposes.
Production volumes of renewable fuels intended for blending into
gasoline are an accurate surrogate for volumes actually blended into
gasoline. In addition, production volumes of renewable fuels capture
those renewable fuels used as motor vehicle fuel in their neat
(unblended) form. Thus we believe that this approach would allow us to
account for all renewable fuels consumed in the U.S. because renewable
fuels always end up being used as fuel in the U.S. or exported.
There are also changes that 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. However, these stock changes always have a net change
of zero over the long term since there is no economic benefit to
stockpiling renewable fuels.
Exports of renewable fuel represent the only 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, we believe that our proposed approach can account for exports
through an explicit requirement placed upon exporters (discussed in
Section III.D.4 below). As a result, we are confident that our proposed
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. A credit trading program would allow a refiner
that overcomplied with its annual RVO to generate credits representing
the excess renewable fuel. The Act stipulates that those credits could
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
would permit current blending practices to continue wherein 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 comply with the standard.
Our proposed RIN-based program would fulfill all the functions of a
credit trading program, and thus would meet 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, banked, or
traded in the next compliance period. RINs could be transferred to
another party in an identical fashion to a credit. However, our
proposed program provides additional flexibility in that it would
permit all RINs to be transferred between parties before they were
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
proposing 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
would be required to verify that the number of RINs generated matched
the volume renewables produced, that any extra value RINs were
appropriately generated, and that RINs numbers were properly assigned
and documented on the renewable fuel PTDs as required by the
regulations.
b. Alternative Approach To Tracking Batches. If we did not
implement 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.
However, this alternative approach would create a number of significant
problems.
First, the parties obligated to meet the standard (refiners,
importers, and blenders of gasoline) are often not the parties who
produce renewable fuel or blend renewable fuels such as ethanol into
gasoline. This separation would require a mechanism for obligated
parties to obtain credit for renewable fuels blended by non-obligated
parties. Generally, this would be done through contract management.
Unfortunately, there might be an incentive to exaggerate the volumes of
renewable fuel blended and thus exaggerate the number of credits
generated. This alternative approach might also create opportunities
for double-counting batches of renewable fuel, either intentionally or
unintentionally.
Second, as described in Section I, one of our guiding principles in
designing the RFS compliance and trading program was to ensure that
existing business practices could continue to the degree possible. With
the alternative approach described above, some refiners might have to
significantly change their business or production practices to take
greater control of ethanol blending and, therefore, the mechanism for
compliance with the RFS program. For instance, a refiner could
establish a contract with an oxygenate blender, securing the rights to
the credits that oxygenate blender creates. A refiner might also decide
to take on more blending responsibilities itself. However, these
approaches would run counter to the normal business practices that keep
fuel costs to a minimum, and would thus have a tendency to increase
fuel costs.
Third, tracking renewable fuel volumes to identify the date, place,
and volume of blending into gasoline would maximize the number of
parties involved, overly complicating the compliance system. There are
approximately 1200 blenders in the U.S. who blend ethanol into
gasoline, in addition to those that blend biodiesel into conventional
diesel fuel. Many of
[[Page 55578]]
these parties are small businesses that have not been regulated in an
EPA fuel program before. Enforcement efforts would necessarily be
placed on them, imposing upon them the primary burden of accurately
documenting the volumes of renewable fuel that are blended into
gasoline even though they are not obligated for meeting the standard.
In contrast, under our proposed program blenders would only need to
keep records of RINs acquired with batches. It is our expectation that
in most cases obligated parties will separate the RINs from batches
before those batches are transferred to blenders. Therefore, blenders
will only have to keep records of RINs for a fraction of the renewable
fuel produced.
Fourth, a focus on the point of blending would not address
renewable fuels that need not be blended into gasoline or diesel. For
example, although biodiesel \28\ is generally blended into conventional
diesel before being used as fuel, it can be used in its neat form
(B100). If volumes of renewable fuel were counted only when blending
into conventional fuel occurred, then B100 could never be claimed by an
obligated party for RFS compliance purposes. The same would be true of
other renewable fuels which, although not produced in significant
quantities today, could play a more substantial role in the renewable
fuels market in the future. Examples of these other unblended renewable
fuels could include renewable diesel made by hydrotreating plant oils
instead of transesterifying them, or a renewable gasoline made from a
Fischer-Tropsch process applied to biogas.
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\28\ Mono-alkyl esters made from plant or animal oils or fats,
and which have been registered with the EPA for use in highway motor
vehicles.
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Finally, a focus on the point of blending would not permit
cellulose biomass ethanol to be distinguished from other forms of
ethanol. Since the Act requires that 250 million gallons of cellulosic
biomass ethanol be produced starting in 2013, this alternative approach
would require tracking of batches of renewable fuel at the producer
level.
In a blender-based approach, then, special exceptions would need to
be developed in order for these neat fuels to be available for RFS
program compliance purposes. For instance, a system of measuring and
tracking neat renewable fuel volumes at the point of production would
likely be necessary. This would be no different from a RIN-based
program for such fuels.
Our proposed RIN-based program would address all these concerns
automatically by shifting the focus of accounting to the point of
production rather than blending. As a result we believe that a blender-
based alternative approach described above is inferior to our proposed
program. We request comment on a RIN-based system for uniquely
identifying, measuring, and tracking batches of renewable fuel for
compliance purposes.
2. Generating RINs and Assigning Them to Batches
a. Form of Renewable Identification Numbers. Each RIN would be
generated by the producer or importer of the renewable fuel and would
uniquely identify not only a specific batch, but also every gallon in
that batch. The RIN would consist of a 34-character code having the
following form:
RIN: YYYYCCCCFFFFFBBBBB RRDKSSSSSSEEEEEE
Where:
YYYY = Calendar year of production or import
CCCC = Company ID
FFFFF = Facility ID
BBBBB = Serial batch number
RR = Code identifying the Equivalence Value
D = Code identifying cellulosic biomass ethanol or waste-derived
ethanol
K = Code identifying extra-value RINs
SSSSSS = Start of volume block.
EEEEEE = End of volume block.
Some examples of RINs are given in Section III.E.1.b.
The company and facility IDs would be assigned by the EPA as part
of the registration process as described in Section IV.B. The serial
batch number would be chosen by the producer and would generally be a
sequential value starting with 000001 at the beginning of each year. We
have chosen five digits for the serial batch number to allow for
facilities that produce up to a hundred thousand batches per year.
However, we request comment on whether four digits would be sufficient.
The RR, D, and K codes would together describe the nature of the
renewable fuel and the RINs that were generated to represent it. The RR
code would simply represent 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 would identify 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.
The K code would be used to specify whether the RIN represents
actual gallons of renewable fuel, or instead represents extra-value
RINs. Extra-value RINs arise only in cases where the Equivalence Value
is greater than 1.0. Extra-value RINs are discussed in more detail in
Section III.D.2.b below.
The RIN also contains two values that together identify the total
number of gallons in a batch as well as uniquely identifying each
gallon in that batch.\29\ When RINs are first assigned to a batch of
renewable fuel by its producer or importer, the volume start block for
that batch will in general be 1 (i.e. SSSSSS will have a value of
000001). The volume block end is the total volume number of gallons in
the batch (i.e. for a 10,000 gallon batch, EEEEEE would have a value of
010000). Thus the single RIN assigned to the batch is in effect
shorthand for all the unique RINs assigned to every individual gallon
in the batch. We propose that the number of gallons in a batch be
standardized to 60 [deg]F to avoid RIN assignment problems associated
with volume swell due to temperature changes. We have assigned six
digits to the volume block codes to allow batches up to a million
gallons in size. We request comment on whether a fewer number of digits
for the SSSSSS and EEEEEE codes would be sufficient.
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\29\ RINs represent actual gallons in a batch when the RIN is a
standard-value RIN. Extra-value RINs represent additional gallons in
cases where the Equivalence Value is greater than Equivalence Value
is greater than 1.0. See further discussion in Section III.D.2.b.
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Since ``RIN'' can refer to either the number assigned to the batch
or the number representing each gallon in that batch, we propose
distinguishing between a batch-RIN and a gallon-RIN. A batch-RIN would
be the multi-character code written on a product transfer document
associated with a batch of renewable fuel. The batch-RIN would include
SSSSSS and EEEEEE values identifying every (volume-standardized) gallon
in the batch, each of which would be assigned its own gallon-RIN. A
gallon-RIN would have identical SSSSSS and EEEEEE values identifying
one gallon in a batch.
Our approach to RINs permits the batch to be divided into smaller
batches at any point in the distribution system while maintaining the
assignment of unique RINs. For instance, if a 1000 gallon batch of
renewable fuel is divided into two 500 gallon batches, the volume block
start and block end values
[[Page 55579]]
in the original batch-RIN would change to reflect the batch split. The
batch-RIN for the first 500 gallon batch would have an SSSSSS value of
000001 and an EEEEEE value of 000500, while the second 500 gallon batch
would have an SSSSSS value of 000501 and an EEEEEE value of 001000.
Additional batch splits would be handled similarly. More discussion of
batch splits is provided in Section III.E.1.b.i.
b. Generating Extra-Value RINs. In general, there is a one-to-one
correspondence between gallon-RINs and physical gallons of renewable
fuel in a batch. For instance, a 10,000 gallon batch of renewable fuel
would be assigned 10,000 gallon-RINs, and the batch-RIN would contain
volume block start and volume block end values summarizing the 10,000
gallon-RINs. However, under certain circumstances RINs may be generated
in addition to those that represent the volume of renewable fuel
actually produced. This would occur in cases where the Equivalence
Value of the renewable fuel in question is greater than 1.0. Renewable
fuel Equivalence Values are discussed in Section III.B.4.
If a renewable fuel has an Equivalence Value greater than 1.0, the
incremental value above 1.0 can be used to generate ``extra-value''
RINs. For instance, the Equivalence Value for biodiesel shown in Table
III.B.4-1 is 1.5. If a biodiesel producer made a 1000 gallon batch of
biodiesel, 1000 standard-value gallon-RINs would be assigned to the
batch and an additional 500 extra-value gallon-RINs could also be
generated.
All the RINs generated to represent a batch of renewable fuel would
contain the same RR code representing the Equivalence Value of the
renewable fuel. However, extra-value RINs would be treated differently
from standard-value RINs in two ways. First, the extra-value RINs would
include a K code that identifies them as extra-value RINs,
distinguishing them from standard-value RINs that represent actual
gallons of renewable fuel. Second, extra-value RINs would not be
required to be transferred along with the batch of renewable fuel as it
moves through the distribution system.\30\ Rather, an extra-value RINs
could be transferred as an independent commodity by the producer. This
approach would provide an incentive for producers to make renewable
fuels that have a comparatively greater value in terms of meeting the
volume requirements of the RFS program. Also, by not requiring extra-
value RINs to be assigned to the batches of renewable fuel that they
represent, batches of renewable fuel can continue to have a one-to-one
correspondence between gallon-RINs assigned to the batch and the number
of physical gallons in that batch. This approach can greatly simplify
the transfer of RINs with batches particularly when batch splits occur.
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\30\ As described in Section III.E below, we are proposing that
standard-value RINs would be assigned to the batch of renewable fuel
they represent and would be required to be transferred with the
batch.
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c. Cases in Which RINs Are Not Generated. Although in general every
(temperature-standardized) gallon of renewable fuel produced or
imported would be assigned a gallon-RIN, there are several cases in
which a RIN may not be assigned. For instance, if a renewable fuel
producer also operated as an exporter, any renewable fuel that it
produced and exported would not need to be assigned a RIN. Since the
gasoline that is blended with renewable fuels under the RFS program
must be ``sold or introduced into commerce'' within the U.S., renewable
fuels that are exported cannot be claimed by an obligated party for
compliance purposes, and therefore would not need to be assigned a RIN.
Exports of renewable fuel are discussed further in Section III.D.4.
Another case in which a RIN may not be assigned to a batch of
renewable fuel would be if the renewable fuel was consumed within the
confines of the production facility where it was made. RINs under
today's proposal would be assigned to renewable fuel when it leaves the
production facility. So long as renewable fuel remained at the
production facility, it would not need to be assigned a RIN.
A third case in which some renewable fuel would not be assigned a
RIN would occur for small volume producers. We are proposing that
renewable fuel producers who produce less than 10,000 gallons in a year
would not be required to generate RINs or assign them to batches. If
they chose to register as a renewable fuel producer under the RFS
program, however, they would be subject to all the regulatory
provisions that apply to all producers, including the requirement to
assign RINs to batches. We request comment on the 10,000 gallon
threshold.
A fourth case in which some renewable fuel would not be assigned a
RIN could occur when a gasoline or diesel blending component is only
partially derived from a renewable source. In such cases the
Equivalence Value associated with the renewable fuel would be less than
1.0, indicating that it is produced by combining a renewable fuel with
a non-renewable fossil fuel. 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.
Equivalence Values are discussed in Section III.B.4. In this situation
only a fraction of the gallons of renewable fuel produced would be
assigned a RIN in proportion to its Equivalence Value, with the
remaining gallons not being assigned a RIN.
Finally, a renewable fuel whose energy content is less than that of
ethanol might also be assigned an Equivalence Value less than 1.0, and
as a result fewer gallon-RINs would be assigned to a batch than
physical gallons in that batch. For example, methanol made from
biogenic methane (biogas) for use in a methanol vehicle would have an
energy content less than that for ethanol. Although methanol is
currently used as a fuel in only very small quantities, if it was
produced from renewable feedstocks it would have an Equivalence Value
less than 1.0.
If a renewable fuel has a Equivalence Value less than 1.0, then
gallon-RINs could only be assigned to a portion of the batch. The
number of gallons within a batch that could be assigned a RIN would be
calculated from the following formula:
Va = EV x Vs
Where:
Va = Volume of the batch that is assigned a RIN, in
gallons (rounded to the nearest whole gallon).
EV = Equivalence Value for the renewable fuel in question (<1.0).
Vs = Total volume of the batch standardized to 60 [deg]F,
in gallons.
In such cases, the volume block start and volume block end values
in the batch-RIN (i.e. SSSSSS and EEEEEE codes described in Section
III.D.2.b) would not exactly correspond to the volume of the batch.
Instead, they would cover the first portion of the batch. The remaining
portion of the batch would not be assigned a RIN. For clarity in
regards to batch splits, a party could assign the gallon-RINs to the
first-out gallons of the batch. Thus if a batch split occurred, every
gallon drawn out of the original batch to form a new, smaller batch
would be assigned a gallon-RIN, up to the point when all the available
gallon-RINs were assigned to the new batch. Any additional gallons
drawn out of the original batch, or left with the original batch, would
have no associated RINs. However, we are not requiring this approach
but only offer it as one possibility. We propose that parties that have
ownership or custody of batches of renewable fuel have the discretion
to split batches and their associated RINs in any way, subject to
[[Page 55580]]
certain restrictions. Batch splits are discussed in more detail in
Section III.E.1.b.i.
3. Calculating and Reporting Compliance
Under our proposed program, RINs would form the basis of the volume
accounting and tracking system that would allow each obligated party to
demonstrate that they had discharged their renewable fuel obligation.
This section describes how the compliance process using RINs would
work. Our proposed 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 proposed program,
each obligated party would 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
produced for use 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, the RVO for each
obligated party is likewise an obligation that is calculated on an
annual basis.
Since our proposed 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 would meet their RVO
through the accumulation of RINs. In so doing, they would effectively
be causing the renewable fuel represented by the RINs to be consumed as
motor vehicle fuel. Obligated parties would not be required to
physically blend the renewable fuel into gasoline or diesel fuel
themselves. The accumulation of RINs would be the means through which
each obligated party would show compliance with its RVO, and thus with
the renewable fuel standard.
For each calendar year, each obligated party would be required to
submit a report to the Agency documenting the RINs it acquired, and
showing that the sum of all gallon-RINs acquired were 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
would have the same compliance value, i.e. there would be no
distinction between standard-value RINs and extra-value RINs for
compliance purposes. The Agency could then verify that the RINs used
for compliance purposes were valid by simply comparing RINs reported by
producers to RINs claimed by obligated parties. We could 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 would be 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 could 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 would be allowed
are determined by the valid life of a RIN, described in more detail in
Sections III.D.3.b below. If alternatively an obligated party has not
acquired sufficient RINs to meet its RVO, then under certain conditions
it could carryover a deficit into the next year. Deficit carryovers are
discussed in more detail in Section III.D.3.d.
The regulations would prohibit any party from creating or
transferring invalid RINs. Invalid RIN could not be used in
demonstrating compliance regardless of the good faith belief of a party
that the RINs were 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
would address the consequences if an obligated party was found to have
used invalid RINs to demonstrate compliance with its RVO. In this
situation, the refiner or importer that used the invalid RINs would be
required to deduct any invalid RINs from its compliance calculations.
The refiner or importer would be liable for violating the standard if
the remaining number of valid RINs was insufficient to meet its RVO,
and the obligated party might be subject to monetary penalties if it
used invalid RINs in its compliance demonstration. In determining what
penalty was appropriate, if any, we would consider a number of factors,
including whether the obligated party did in fact procure sufficient
valid RINs to cover the deficit created by the invalid RINs, and
whether the purchaser was indeed a good faith purchaser based on an
investigation of the RIN transfer. A penalty might include both the
economic benefit of using invalid RINs and/or a punitive component.
Although an obligated party would be liable under our proposed
program for a violation if it used invalid RINs for compliance
purposes, we would normally look first to the generator/seller of the
invalid RINs both for payment of penalty and to procure sufficient
valid RINs to offset the invalid RINs. However, if that party was found
to be out of business, then attention would turn to the obligated party
who would have to obtain sufficient valid RINs to offset the invalid
RINs.
As for RIN generators, we are proposing that obligated parties be
required to 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 would verify the volume
of renewable fuel exported and therefore the magnitude of their RVO.
Attest engagement reports would be submitted to the party that
commissioned the engagement, and to EPA.
b. Valid Life of RINs. The Act requires that renewable fuel credits
be valid to show compliance for 12 months as of the date of generation.
This section describes our proposed interpretation of this provision in
the context of a RIN-based program. We also discuss some possible
alternative interpretations that we have considered.
As described in Section III.D.1.a, credits 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, compliance would be determined shortly after the end
of the year, and credits would be identified at that time. Compliance
is typically demonstrated 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.
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 market. 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
[[Page 55581]]
crude oil dropped significantly and the use of ethanol in gasoline
became 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 find themselves with a stranded
investment. The 12 month valid life limit for credits minimizes the
potential for this type of result.
For obligated parties, the 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
credit 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 thus 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 RINs,
and thus ethanol blends, could spike 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 these potential price
spikes. 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 proposed RIN-based program, we are 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
the following year. RINs not used for compliance purposes in the year
in which they were generated would by definition be in excess of the
RINs an obligated party needed in that year, making excess RINs
equivalent to credits. Excess RINs would be valid for compliance
purposes in the year following the one in which they initially came
into existence.\31\ RINs not used within their valid life would expire.
This would satisfy the Act's 12 month duration for credits.
---------------------------------------------------------------------------
\31\ The use of previous-year RINs for current year compliance
purposes would also be limited by the 20 percent RIN rollover cap
under today's proposal. However, as discussed in the next section,
we believe that this proposed cap will still provide a significant
amount of flexibility to obligated parties.
---------------------------------------------------------------------------
Thus we propose 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 could 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 would expire.
There are alternative approaches that could be taken to
establishing the valid life of a RIN. For instance, excess RINs could
be deemed to be generated not at the end of an annual compliance
period, but rather on the date that an obligated party must submit its
annual report to the Agency (February 28 as described in Section
IV.A.2). In this case the 12-month valid life could extend into the
following calendar year. As described above, the fact that compliance
is determined on an annual basis means that RINs that are valid for any
portion of a calendar year should be available for demonstrating
compliance with that year's compliance obligation. Under this
alternative approach, RINs would be valid for three full compliance
periods: the calendar year in which the original RIN came into
existence, the following year during which it was deemed to be in
excess of an obligated party's RVO, and a third year within which the
12 month valid life expired. We do not believe that this interpretation
is most consistent with the Act's purposes. This could allow a given
year's exceptional overcompliance to effectively reduce required
renewable fuel volumes for two years in the future. We do not believe
that this would promote the best balance between allowing flexibility
for obligated parties while also increasing the use of renewable fuels
annually.
Another possible approach to RIN life would be to interpret the
Energy Act's 12-month credit life provision as applying
retrospectively, not prospectively. Under this approach, the 12-month
timeframe in the Act would be interpreted to refer to the calendar year
within which a credit was generated. If excess RINs were deemed to be
such on December 31, then under this alternative approach no RINs could
be used for compliance purposes beyond the year in which they
originally came into existence.
However, 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 believe that it is appropriate for all
RINs to be valid for the year in which they were generated and the
following calendar year. In comparison to a single-year valid life for
RINs, our proposed 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 to a minimum.
We recognize that the language of the Act regarding credit valid
life is not unequivocal. However, 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. The record of
the development of this legislation does not provide a clear indication
to the contrary. In fact, while some stakeholders have argued that the
Energy Act could have been written to explicitly allow a valid life of
multiple years if that had been Congress' intent, we believe it could
likewise have been written to explicitly limit the valid life to the
year in which the renewable fuel was produced if that had been its
clear intent. Therefore, the interpretation of the valid life language
in the Act must be established in the context of the statutory
requirements for the full RFS program and the practical implications of
its implementation.
One possible objection to our proposed approach is 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. However, the language
in the Act shows that Congress clearly intended a credit program that
provided a degree of implementation flexibility. 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
[[Page 55582]]
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.
We request comment on the valid life of RINs, including our
proposed approach in which RINs would be valid for the year generated
or the following year, and the alternative approaches in which RINs
would be valid for more or less time than under our proposal.
c. Cap on RIN Use to Address Rollover. As described in Section
III.D.3.b above, we are proposing that RINs be valid for compliance
purposes for the calendar year in which they were 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 proposed 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 example below illustrates the issue.
Table III.D.3.c-1.--Example of RIN Rollover Issue
[Billion RINs]
----------------------------------------------------------------------------------------------------------------
Available RINs Compliance Determination
-----------------------------------------------------------------------------
New excess
Required RINs Excess Previous Additional RINs
under RFS a generated b year RINs RINs needed generated
----------------------------------------------------------------------------------------------------------------
2007.............................. 4.7 5.2 0.5 0.0 4.7 0.5
2008.............................. 5.4 6.0 0.6 0.5 4.9 1.1
2009.............................. 6.1 6.9 0.8 1.1 5.0 1.9
----------------------------------------------------------------------------------------------------------------
a Equivalent to the required volumes shown in Table I.B-1.
b One possible production volume scenario based on EIA projections in their Annual Energy Outlook 2006.
In this example, there are 0.5 billion more RINs available for
compliance year 2007 than are needed to comply with the RFS program
requirements. Since these RINs are not used in the year in which they
are generated (2007), they can be used for compliance purposes in the
following year (2008). If they are not used in 2008, they will expire.
In 2008, 0.6 billion more RINs come into existence than are needed
to meet the 2008 requirements. This should mean that there are 0.6
billion more RINs available than are needed to comply with the RFS
program requirements for 2008, and thus 0.6 billion RINs should be
carried into 2009. However, since there are also 0.5 billion RINs
available from the previous year which can be used for compliance
purposes in 2008, this permits the generation of 0.5 new excess RINs in
2008 if all the 2007 RINs are used to demonstrate compliance in 2008.
Thus there are in fact 1.1 billion excess RINs generated in 2008 rather
than only 0.6 billion, and they can all be used for compliance purposes
in 2009. In summary, the excess RINs from 2007 were used to generate
new excess RINs in 2008, and in effect (though not by record) the
excess RINs from 2007 can be used for compliance purposes in 2009, a
year after they should have expired. Thus excess RINs have ``rolled
over'' multiple years.
The rollover issue essentially could make the applicable valid life
for RINs virtually meaningless in practice. Even though individual RINs
technically could only be used for compliance purposes for the year
generated and the following year, in practice obligated parties could
use previous-year RINs to generate new excess current-year RINs which
could then be carried into the following year. This could continue for
every year in which the volume of renewable fuel produced in a given
year exceeds the RFS requirements for that year, up to limit of 100
percent of the standard for that year. The net result is that the RFS
program could operate as if there was virtually no valid life limit for
RINs at all.
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.
Some stakeholders do not perceive a problem with the RIN rollover
issue. They point to the need for maximum flexibility in responding to
fluctuations in the market, and they are 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 even returned to the 1995 levels. 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.
Obligated parties have 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
[[Page 55583]]
and the Agency does not waive any portion of the program requirements.
We believe that the rollover issue can and should 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 have a de facto 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. We considered a number of
possible approaches for accomplishing this, some of which are discussed
below. After consultation with stakeholders, we decided that the best
approach would be to place a percentage cap on the amount of an
obligated party's Renewable Volume Obligation (RVO) that can be met
using previous-year RINs. We are proposing that this cap be set at 20
percent. Thus each obligated party would 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. The cap would not be
effective until compliance year 2009, since no rollover is possible in
years 2007 or 2008.
Any previous-year RINs that an obligated party may have that are in
excess of the 20 percent cap could be traded to other obligated parties
that need them. If the previous-year RINs in excess of the 20 percent
cap were not used by any obligated party for compliance, they would
expire. The net result would be that, for the market as a whole, no
more than 20 percent of a given year's renewable fuel standard could be
met with RINs from the previous year.
Furthermore, we believe that the 20 percent cap provides the
appropriate balance between, on the one hand, allowing legitimate RIN
carryovers and protecting against potential supply shortfalls that
could limit the availability of RINs, and on the other hand ensuring an
annual demand for renewable fuels as envisioned by the Act. We believe
this approach also provides the certainty all parties desire in
implementing the program. The same cap would apply equally to all
obligated parties, and the cap would 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 would be readily
enforceable with minimal additional program complexity, as each
obligated party's annual report would simply provide separate listings
of previous-year and current-year RINs to establish that the cap had
not been exceeded. A 20 percent cap would have no impact on who would
own RINs, their valid life, or any other regulatory provision regarding
compliance.
Rather than employing a fixed 20 percent cap, we also considered an
approach whereby we would set the cap annually based on the actual
excess renewable fuel production. Table III.D.3.c-2 provides an example
of how the caps would be calculated if the EIA projections for ethanol
production prove accurate.
Table III.D.3.c-2.--Required and Projected Renewable Fuel Volumes
[Billion gallons]
----------------------------------------------------------------------------------------------------------------
Previous
Year excess
ethanol as
Required Ethanol a fraction
under RFS a produced b Excess d of current
year
compliance
(percent)
----------------------------------------------------------------------------------------------------------------
2008........................................................ 5.4 6.0 0.6 ...........
2009........................................................ 6.1 6.9 0.8 9.8
2010........................................................ 6.8 7.9 1.1 11.8
2011........................................................ 7.4 8.8 1.4 14.9
2012........................................................ 7.5 9.6 2.1 18.7
2013........................................................ c 7.6 10.1 2.5 27.6
2014........................................................ c 7.8 10.3 2.5 32.1
2015........................................................ c 7.9 10.5 2.6 31.6
----------------------------------------------------------------------------------------------------------------
a Equivalent to the required volumes shown in Table I.B-1
b Projected ethanol production volumes from EIA, Annual Energy Outlook 2006.
c Example of possible increases in the required volumes. The Energy Act requires at minimum a constant
percentage of renewable fuel in gasoline after 2012.
d Does not include other renewable fuels such as biodiesel which would increase the excess even further.
In 2009, for instance, the cap would be 9.8 percent, and by 2012 it
would be 18.7 percent. Under such an approach, the value of the cap
might more precisely reflect the actual excess RINs and preclude their
rollover. However, the annual calculation of the cap would require that
the total renewable fuel volumes from the previous year be known. For
compliance year 2009, information on 2008 renewable fuels production
would not generally be known until spring of 2009. Therefore, obligated
parties would not know until mid-year at the earliest what the exact
cap would be for that year. The Agency could publish an estimate of the
cap by the end of the previous year, but it would not provide obligated
parties with the certainty they may need for establishing contracts and
business relationships for RIN trading. In addition, such a variable
cap may not ensure a smoothly functioning RIN market under all possible
market conditions. Market flexibility is needed most when the RIN
market is the tightest (i.e. when renewable fuel production volumes are
closest to the volumes required under the RFS program). Yet under this
alternative approach, the cap would be the smallest when supply was
closest to demand for
[[Page 55584]]
RINs. The cap would approach zero as supply approached the volumes
required under the RFS program, and thus an obligated party that had
even a small number of excess RINs from the prior year could not use
them, but rather would be forced to trade them to someone else.
Conversely, when supply significantly exceeds demand and market
flexibility is needed least, the cap would be the highest. 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.
The level of 20 percent is also consistent with both past ethanol
market fluctuations and future projections of excess ethanol. 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.
Furthermore, as illustrated in Table III.D.3.c-2, EIA projections
indicate that previous year volumes will exceed current-year
requirements by roughly 10 to 30 percent between 2009 and 2015. Our
proposed 20 percent cap lies in the midrange of these values.
As a result, we believe that a cap of 20 percent appears to be 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 would also ensure that many previous-year RINs can still be
used for current year compliance, providing some flexibility in the
event of market disruptions.
Despite the flexibility it would provide, a cap of 20 percent would
not be guaranteed to be sufficient to address every potential future
supply shortfall or fluctuation in the renewable fuels market. Thus we
request comment on whether a higher cap, such as 30 percent, would be
more appropriate. On the other hand, since EIA is projecting that a cap
of 20 percent will be more than what is necessary in the first few
years of the program to address rollover, we also request comment on
whether a smaller cap, such as 10 percent, would be appropriate.
We also request 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.
In addition to our proposed 20 percent cap, we also evaluated an
alternative approach for addressing the RIN rollover issue. Under this
alternative, we would not employ a uniform cap at all, but rather would
require current-year RINs to be applied towards an obligated party's
RVO before any previous-year RINs were considered. This ``last-in,
first-out'' (LIFO) approach would eliminate the possibility that
previous-year RINs could be used to generate new excess current-year
RINs, forcing them to expire. Although it would focus the RIN rollover
correction on obligated parties and would tailor it to the specific
circumstances of each party, this alternative approach would also
create the need for an additional regulatory prohibition. Under this
approach, RINs held by non-obligated parties would not automatically
expire. As a result, non-obligated parties could in essence serve as a
bank of previous-year RINs, thus permitting the rollover to continue
despite the imposition of a LIFO protocol. To prevent this, the LIFO
approach would have to include a requirement that non-obligated parties
be prohibited from owning previous-year RINs. If a non-obligated party
were to own a current-year RIN on December 31 and hold it until January
1, that RIN would automatically expire. In order to enforce this
provision, the Agency would also need to keep track of and receive
reports on all RIN transactions for non-obligated parties by their
transaction date.
Given the additional uncertainty and complexity caused by this
alternative approach, we believe that our proposed 20 percent cap
provides the greatest degree of simplicity and flexibility while still
addressing the RIN rollover issue. However, we request comment on any
alternative approaches to addressing the RIN rollover issue.
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 generate or purchase sufficient credits to
meet 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 has not acquired 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 deficit carryover. As described in
Section III.D.1, the deficit is then added to the RVO for the next
year. The calculation of the RVO as described in Section III.A.4 shows
how a deficit would be carried over into the next year:
RVOi = Stdi x GVi +
Di-1
Where:
RVOi = The Renewable Volume Obligation for the obligated
party for year i, in gallons
Stdi = The RFS program standard for year i, in percent
GVi = The non-renewable gasoline volume produced by an
obligated party in year i, in gallons
Di-1 = Renewable fuel deficit carryover from the previous
year, in gallons.
If an obligated party does 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 would 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 are not proposing that any particular
demonstration of ``inability'' be a prerequisite to the ability of
obligated parties to carry deficits forward. However, we request
comment on this issue.
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 proposed 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 should
[[Page 55585]]
not be 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.
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. Ideally the producer of the exported renewable fuel would
simply not create RINs for those batches. However, in the fungible
distribution system it is common for exportation of fuel to occur
without the knowledge of the producer. As a result, we cannot rely on
the producers to know which batches will be exported and to not
generate RINs for those batches. Another approach would be to increase
the obligation placed on refiners, importers, and blenders of gasoline
based on the volume of renewable fuel exported. Obligated parties would
thus acquire RINs to meet the standard described in Section III.A, and
would also be required to acquire RINs to cover the volume of renewable
fuel exported. However, this approach would not only require 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 exports.
Given these drawbacks, we believe that these two approaches would
be unworkable. As a result, we believe that it should be the exporter's
responsibility to account for exported renewable fuel. The most
straightforward mechanism to accomplish this would be to assign an RVO
to each exporter that is equal to the annual volume of renewable fuel
it exported. Just as for obligated parties, then, the exporter would be
required to acquire sufficient gallon-RINs to meet its RVO. If the
exporter purchased renewable fuel directly from a producer, that
renewable fuel would come with associated gallon-RINs which could then
be applied to its RVO under our proposed program. In this circumstance,
the exporter would not need to acquire RINs from any other source. If,
however, the exporter received renewable fuel without the associated
RINs, it would need to acquire RINs from some other source in order to
meet its RVO.
As discussed in Section III.D.2.c, it may be possible to eliminate
the need for RINs altogether in specific circumstances involving
exports of renewable fuels. 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. Likewise if a renewable fuel producer
specifically and explicitly earmarked a batch of renewable fuel for
export, there would be no need for a RIN to be generated. However, in
both of these cases the producer would need to report the volumes that
were not assigned a RIN to the EPA in its annual RFS report, along with
the connection to exports, in order to demonstrate that RINs were
legitimately not assigned to these batches. We request comment on these
special-case approaches to exported renewable fuels.
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 RINs generated for that batch. For instance, extra-value
RINs can be generated in cases where the Equivalence Value is greater
than 1.0. If the RVO assigned to the exporter were based strictly on
the actual volume of the exported product, it would not capture the
extra-value RINs which generally are not assigned to batches. Thus we
propose 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 would multiply the actual volume of a
batch by 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 propose that for
such cases the exporter simply 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 renewable fuel had in
fact been assigned an Equivalence Value greater than 1.0. However, we
believe that the potential impact of this error would be exceedingly
small. We request comment on our proposed approach to exporters of
renewable fuel and any alternative approaches that could ensure that
production volumes of renewable fuel can be used as an accurate
surrogate for consumed volumes.
5. How Would the Agency Verify Compliance?
The primary means through which the Agency would verify an
obligated party's compliance with its RVO would be the annual reports.
These reports would include a variety of information required for
compliance and enforcement, including the demonstration of compliance
with the previous calendar year's RVO, a list 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 would 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 would 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 would also indicate which RINs were used for compliance
with the RVO including any potential deficit, which current-year RINs
were not used for compliance and would therefore be valid for
compliance the next year, and which previous-year RINs were not used
for compliance and therefore expired. The report would also include a
demonstration that the 20 percent cap to address RIN rollover had been
met, as described in Section III.D.3.c.
In order to verify compliance for each obligated party, the primary
Agency activity would involve the validation of RINs. There are four
basic elements of RIN validation:
(1) RINs used by an obligated party to comply with its RVO would 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 would be cross-checked
with annual 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
would 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 would be
checked to ensure that they do not exceed 20 percent of the obligated
party's RVO.
In cases where a RIN was highlighted under suspicion of being
invalid, the Agency would then need to take additional steps to resolve
the issue. In
[[Page 55586]]
general this would involve a review of RIN transfer records submitted
to the Agency by all parties in the distribution system that held the
RINs. RIN transfers would be recorded through EPA's Central Data
Exchange as described in Section IV. These RIN transfer records would
permit the Agency to identify all transaction(s) involving the RINs in
question. Liable parties could then be contacted and appropriate steps
taken 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 proposed program structure, a Renewable Identification
Number (RIN) would be generated for every gallon of renewable fuel
produced or imported into the U.S., and would be acquired by obligated
parties for use in demonstrating compliance with the RFS requirements.
However, there are a variety of ways in which RINs could be transferred
from the point of generation by renewable fuel producers to the
obligated parties that need them.
EPA's proposal was developed in light of the somewhat unique
aspects of the RFS program. As discussed earlier, under this program
the refiners and importers 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 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, EPA believes the
RIN transfer mechanism should focus first on facilitating compliance by
refiners and importers, and doing that in a way that imposes minimum
burden on other parties and minimum disruption of current mechanisms
for distribution of renewable fuels.
Our proposal 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. EPA's proposal would basically have the RIN
follow with the ethanol until the point the ethanol is purchased by the
obligated party, or is blended into gasoline by a blender. This
approach would allow the RIN to be incorporated into the current market
structure for sale and distribution of ethanol, and would avoid
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 proposed program, it is also not required.
The Agency has also evaluated several other options for
distributing RINs. We are not proposing 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. At the same time, we recognize that all of the alternatives
described below, as well as our proposal, have differing positive and
negative aspects, and we invite comment on them, especially comments
comparing and contrasting them with our proposed program. Our proposal
is described in subsections 1 through 3 below, and alternative
approaches in subsection 4.
1. Distribution of RINs With Batches of Renewable Fuel
We are proposing that standard-value RINs be transferred with
actual batches of renewable fuel as they move through the distribution
system, until ownership of the batch is assumed by an obligated party
or by a party that converts the renewable fuel into motor vehicle fuel.
After such time, the RINs could be separated from the batch and freely
traded. This approach would place 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 specific batches of
renewable fuel would 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. They would
construct each batch-RIN based on the particular circumstances
associated with each batch, including the creation of a unique serial
number for the batch and specifying its Equivalence Value. The batch-
RIN would also identify the specific number of gallons in the batch,
thereby summarizing the gallon-RINs assigned to every gallon in the
batch. See Section III.D.2.a for details on our proposed format for
RINs.
Only standard-value RINs would have to be assigned to batches.
Extra-value RINs could be generated by the renewable fuel producer in
cases where the renewable fuel in question has an Equivalence Value
greater than 1.0 (see Section III.D.2.c for further discussion).
However, the extra-value RINs would not need to be assigned to the
batch. Instead, they could be transferred to another party independent
of the batch. This requirement would in general result in a one-to-one
correspondence between gallons in a batch and the volume block numbers
in the batch-RIN assigned to that batch. As a result, the process of
dividing and combining RINs during batch splits and mergers would be
simplified, and the fungibility of RINs in the distribution system
would be maintained. For example, a marketer who took custody of
ethanol batches from several different producers, including a producer
of cellulosic biomass ethanol, and combined them all in a single tank
could then withdraw batches of any size from the tank, and assign a
number of gallon-RINs to each batch that is equivalent to the number of
actual gallons in that batch. This approach would also provide an
incentive for producers to produce renewable fuels with higher
Equivalence Values, since they could transfer the extra-value RINs to
any party.
However, we are also proposing that producers have the option of
assigning even extra-value RINs to batches if they chose to do so.
Under these circumstances, the extra-value RINs would be treated just
like standard-value RINs, and thus would be subject to the same
limitations on who can separate the RIN from the batch. The assignment
of extra-value RINs to batches would also mean that the number of
gallon-RINs assigned to the batch would be greater than the number of
gallons in the batch. As a result, care would have to be taken during
batch splits and batch mergers to appropriately pass RINs assigned to a
parent batch on to the daughter batches. We request comment on allowing
extra-value RINs to be assigned to batches.
There are two other cases in which the gallon-RINs assigned to a
batch would 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 RINs could only be assigned to a portion of the batch. Such
potential circumstances are described in Section III.D.2.d. RINs may
also not correspond exactly to gallons if the density of the batch
changes due to changes in temperature. For instance, under extreme
changes in temperature, the volume of a batch of ethanol can change by
5 percent or more. For this
[[Page 55587]]
reason we are proposing that all batch volumes be corrected to
represent a standard condition of 60 [deg]F prior to the assignment of
a RIN. For ethanol,\32\ we propose that the correction be done as
follows:\33\
\32\ An appropriate temperature correction for other renewable
fuels should likewise be used.
\33\ 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
would be consistent with current practices and would maintain the one-
to-one correspondence between the volume block in the batch-RIN and the
standardized volume of the batch. We propose a similar approach to
biodiesel, where the volume correction can be calculated using the
following equation:\34\
---------------------------------------------------------------------------
\34\ 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.
The RIN would have to be assigned to a batch no later than the
point in time when the batch physically leaves the production or
importing facility. Although ownership of the batch may be retained by
the producer or importer, the RIN would nevertheless be required to be
transferred along with the batch as it leaves the originating facility.
This requirement would ensure that RINs could be verified against
production or importing facility records and against mandated reports
to the Energy Information Administration (EIA). It would also
centralize the process of assigning RINs to batches.
The means through which RINs would be transferred with batches
would in some respects be left to the discretion of the renewable fuel
producer or importer. The primary requirement would be that the RIN be
included 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 batch. The batch documentation must be
of the sort that uniquely identifies the batch and is generally
transferred from one party to another, in electronic or paper form,
when ownership of the batch is transferred. In many cases a bill-of-
lading could serve this purpose. The RIN must be displayed prominently
on the document when the batch leaves the originating facility, so that
parties taking ownership of the batch could make a record of this fact
with specific reference to the RIN. The RIN must be included on a PTD
whenever ownership or custody of the batch is transferred, until such
time as the RIN may be separated from the batch as described in Section
III.E.2. 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 would be transferable in the context of the RFS program, and
except as discussed above, must be transferred along with ownership or
custody of the batch. The approach that a producer or importer takes to
the transfer or sale of RINs and batches would be at their discretion,
under the condition that the two be transferred or sold simultaneously
and to the same party.
b. Responsibilities of Parties That Buy, Sell, or Handle Renewable
Fuels. Batches 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 batches, 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 batch of renewable fuel can be owned or held by
any number of parties including marketers, distributors, terminal
operators, and refiners. Under our proposed program, when any party
takes ownership of a batch of renewable fuel prior to ownership of the
batch of fuel by an obligated party or blender, the RINs associated
with that batch must be transferred as well. The RINs would be included
on PTDs that the party procures when taking ownership of a batch.
We propose that in general all parties that assume ownership of any
batch of renewable fuel be required to transfer all RINs assigned to
that batch to another party to whom ownership of the batch is being
transferred. Batch splits and batch mergers represent special cases of
RIN transfers, and are described in more detail below. As described in
Section III.E.2, the only exception to the requirement that RINs be
transferred with batches would be parties who are obligated to meet the
renewable fuel standard, and parties who convert the renewable fuel
into motor vehicle fuel. Since our proposed program is designed to
allow RIN transfer and documentation to occur as part of normal
business practices in the context of renewable fuel distribution, the
incremental costs of transferring RINs with batches should be minimal.
Marketers and distributors would simply be adding the batch-RIN to
transfer documents such as bills-of-lading, and recording the batch-
RINs in their records of batch purchases and sales.
Under most other credit trading programs, parties obligated to meet
a standard are also the parties that generate credits for trade. Under
these systems, non-obligated parties can participate only to the degree
that obligated parties explicitly include them. In the case of the RFS
program, however, the production of renewable fuels and their
conversion into motor vehicle fuel through blending is largely done by
persons other than obligated parties. To the degree that our proposed
program allowed the disparity between RFS obligations and the means of
compliance to continue, stakeholders have expressed concerns about a
variety of problems that could arise, such as market power by RIN
sellers in the market where RINs are exchanged. Market power on the
part of non-obligated parties could result in higher prices for RINs
than prices that would arise in a competitive, well-functioning market
setting. For instance, if a renewable fuel producer or marketer could
separate the batch-RIN from the batch, he could in theory withhold the
RIN from the marketplace temporarily. By the end of an annual
compliance period, a scarcity of RINs could increase their price, at
which point the renewable fuel producers or marketers could begin to
sell the RINs at an inflated price. In the extreme such parties could
potentially withhold a large number of RINs from the market, creating a
scarcity of RINs that could compel obligated parties to purchase
additional volumes of renewable fuel with associated RINs. These
scenarios are of particular concern given that we expect there will be
a relatively small number of renewable fuel producers and marketers
selling RINs in the
[[Page 55588]]
marketplace. For instance, although there currently exist about 100
ethanol production facilities in the U.S., nearly half of the
production volumes come from only seven companies. Likewise, only five
companies manage the majority of ethanol marketing.
We believe that the general prohibition against the separation of
RINs from batches in the distribution system will place only a small
additional burden on marketers and distributors of renewable fuel.
According to several stakeholders, a large amount of ethanol is already
purchased from renewable fuel producers directly by refiners. In these
cases, the RIN would be transferred directly from the renewable fuel
producer to an obligated party. For the remaining batches of ethanol
that do experience multiple transfers before being blended into
gasoline, the RIN itself would represent a small incremental item of
information that must be recorded and transferred along with batches
and could be included in normal business records.
In addition to the recordkeeping responsibilities described in more
detail in Section IV, parties that would be required to transfer RINs
with batches under our proposed program would also have the primary
responsibility of maintaining the integrity of RIN-batch pairing when
batches are split or merged. Our proposed approach to these situations
is described below.
i. Batch splits
As described in Section III.D.2, batch-RINs assigned to batches of
renewable fuel would be formatted such that the volume block codes
(SSSSSS and EEEEEE) would identify every gallon in a batch, and thus
every gallon-RIN. Thus in most cases there will be a one-to-one
correspondence between gallons in a batch and the volume block codes
for the batch-RIN assigned to that batch. If a batch of renewable fuel
is split into two or more new batches, the gallon-RINs assigned to the
original batch can be split coincidentally with batch volumes. The
following example shows how this would be done (volume blocks separated
for clarity):
Parent batch:
1000 gallons,
batch-RIN: 2007123412345000011021-000001-001000.
Daughter batch #1:
600 gallons,
batch-RIN: 2007123412345000011021-000001-000600.
Daughter batch #2:
100 gallons,
batch-RIN: 2007123412345000011021-000601-000700.
Daughter batch #3:
300 gallons,
batch-RIN: 2007123412345000011021-000701-001000.
In this example, the gallon-RINs remain both unique and paired on a
one-to-one basis with actual gallons even after the parent batch is
divided into smaller daughter batches.
However, there will be some cases in which there is not a one-to-
one correspondence between a RIN assigned to a batch and the actual
gallons in that batch, and such cases could complicate the process of
splitting batches. For instance, changes in temperature could cause
batch volumes to swell or shrink. Renewable fuels with Equivalence
Values less than 1.0, although currently unlikely to arise in
appreciable volumes, will have more actual gallons in the original
batch than RINs assigned to that batch. And some producers may choose
to assign extra-value RINs to batches in cases wherein the Equivalence
Value is greater than 1.0.
To address such cases, we propose to allow parties in the
distribution system the discretion to split batches and their assigned
RINs following any protocol they choose, as long as that protocol
preserves the requirement that gallon-RINs that have been assigned to a
batch by the producer are subsequently assigned to a batch after
splitting has occurred. Thus regardless of the splitting protocol used,
no gallon-RINs assigned to a batch could be retained by a party after
every gallon in that batch has been transferred to another party.
There are a variety of batch splitting protocols that a party could
choose from for situations where there is not a one-to-one
correspondence between the number of gallon-RINs assigned to a batch
and the number of standardized gallons in that batch. However, we have
identified two acceptable protocols that we expect most parties to use.
These are described in Table III.E.1.b.i-1 below. Examples of batch
splits using both types of splitting protocols are given in Tables
III.E.1.b.i-2 and III.E.1.b.i-3. We propose that the Proportional
Protocol be required for cases in which the Equivalence Value of a
renewable fuel is less than 1.0. For cases in which the Equivalence
Value is equal to or greater than 1.0, we propose to allow parties the
flexibility to follow a batch splitting protocol of their own choosing
so long as there is at least one gallon-RIN for every physical gallon
in each of the daughter batches. We request comment on these batch
splitting protocols, any alternative protocols, and the need to codify
a protocol in the regulations for specific situations.
Table III.E.1.b.i-1.--Two Batch Splitting Protocols
------------------------------------------------------------------------
Proportional One-to-one alignment
------------------------------------------------------------------------
Description................. The gallon-RINs The gallon-RINs
assigned to a assigned to a
parent batch are parent batch are
split split to ensure
proportionally with that some daughter
the volumes in the batches have a one-
daughter batches. to-one
correspondence
between physical
gallons and gallon-
RINs. Remaining
gallon-RINs are
assigned to
remaining gallons.
Impacts for EV \a\ < 1.0.... Ratio of actual Some daughter
gallons to gallon- batches may have no
RINs in the parent assigned RIN.
batch is preserved
in all daughter
batches.
Impacts for EV > 1.0........ Ratio of actual Ratio of actual
gallons to gallon- gallons to gallon-
RINs in the parent RINs in some
batch is preserved daughter batches
in all daughter will be different
batches. than the ratio for
the parent batch.
------------------------------------------------------------------------
a Equivalence Value.
[[Page 55589]]
Table III.E.1.b.i-2.--Example of Proportional Batch Splitting
------------------------------------------------------------------------
EV < 1.0 EV > 1.0
------------------------------------------------------------------------
Parent batch:
Actual volume (gal)........................... \1\ 1000 \1\ 1000
Batch-RIN SSSSSS code......................... 000001 000001
Batch-RIN EEEEEE code......................... 000800 002500
Number of gallon-RINs......................... 800 2500
Daughter batch 1:
Actual volume (gal)........................... \1\ 600 \1\ 600
Batch-RIN SSSSSS code......................... 000001 000001
Batch-RIN EEEEEE code......................... 000480 001500
Number of gallon-RINs......................... 480 1500
Daughter batch 2:
Actual volume (gal)........................... \1\ 400 \1\ 400
RIN volume block start (SSSSSS)............... 000481 001501
RIN volume block end (EEEEEE)................. 000800 002500
Number of gallon-RINs......................... 320 1000
------------------------------------------------------------------------
\1\gal.
Table III.E.1.b.i-3--Example of Batch Splitting With One-to-One
Alignment
------------------------------------------------------------------------
EV < 1.0 EV > 1.0
------------------------------------------------------------------------
Parent batch:
Actual volume (gal)........................... \1\ 1000 \1\ 1000
Batch-RIN SSSSSS code......................... 000001 000001
Batch-RIN EEEEEE code......................... 000800 002500
Number of gallon-RINs......................... 800 2500
Daughter batch 1:
Actual volume (gal)........................... \1\ 600 \1\ 600
Batch-RIN SSSSSS code......................... 000001 000001
Batch-RIN EEEEEE code......................... 000600 000600
Number of gallon-RINs......................... 600 600
Daughter batch 2:
Actual volume (gal)........................... \1\ 400 \1\ 400
Batch-RIN SSSSSS code......................... 000601 000601
Batch-RIN EEEEEE code......................... 000800 002500
Number of gallon-RINs......................... 200 1900
------------------------------------------------------------------------
\1\gal.
ii. Batch mergers.
In general batch mergers will begin with at least two parent
batches having different RINs. After the merger of the two parent
batches, the RINs from the two parents would simply need to be listed
separately on any product transfer documents such as bills-of-lading,
since they differ not just in the volume block codes but also in other
aspects of the RIN. We are not proposing any mechanism for simplifying
the RIN in the case of a batch merger, such as combining two different
RINs into a single RIN or replacing a collection of different RINs with
a new single RIN. We believe that such approaches would be likely to
create significant difficulties in tracking RINs and verifying their
validity.
Parties that have two or more batches of renewable fuel that have
been merged into a single batch will be free to determine how the RINs
will be subsequently split and assigned to new daughter batches during
a batch split. We are not proposing a specific protocol for such cases,
beyond the general requirement that RINs that have been assigned to
parent batches remain assigned to a daughter batch after splitting has
occurred. However, it may be helpful for RINs to be ordered on PTDs in
the order in which the batches were combined, and then assigned to
daughter batches on a first-in, first-out basis. Thus as individual
parent batches are added to, for instance, a tank already containing
renewable fuel, the RINs associated with the newly added batch could be
added below the existing RINs on the documentation. As product was
drawn back out of the tank, the RINs assigned to the removed product
would be those at the top of the list of RINs on the tank
documentation. This FIFO approach would ensure that RINs assigned to
parent batches continue to move through the distribution system, and
batch splits could occur straightforwardly even in cases that begin
with merged batches. We request comment on whether this FIFO approach
should remain guidance or whether instead it should be a regulatory
requirement.
2. Separation of RINs From Batches
Separation of a RIN from a batch means that the RIN would no longer
be included on the PTD, and could be traded independently from the
batch to which it had originally been assigned.
We believe that the regulatory program should be structured around
facilitating compliance by obligated parties with their renewable fuel
obligation. This means that obligated parties should have the right to
market the renewable fuel separately from the RIN originally assigned
to it. We are therefore proposing that a refiner or importer would have
the right to separate the RIN from the batch as soon as he assumes
ownership of that batch. 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
[[Page 55590]]
blending with gasoline. Therefore, in many cases RINs assigned to
batches 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 believe
that a blender should also have the right to separate the RIN from the
batch if he actually blends the ethanol into gasoline. This would only
apply to batches where the RIN had not already been separated by an
obligated party. Since blenders would in general not be obligated
parties under our proposed program, blenders who separate RINs from
batches would have no need to hold onto those RINs and thus could
transfer them to an obligated party for compliance purposes, or to any
other party.
There may be occasions in which a downstream customer actually owns
the batch of ethanol when it is blended into gasoline. In such cases
the blender will have custody but not ownership of the batch. We
propose that the RIN can be separated from the batch of ethanol when
the batch is blended into gasoline, but the RIN could only be separated
by the party that owns that batch of renewable fuel at the time of
blending.
Once a RIN is separated from a batch of renewable fuel, the PTDs
associated with that batch could no longer list the RIN. Parties who
subsequently take ownership of the batch may not know if the RIN had
been separated, or if a RIN had never been assigned to the batch in the
first place, contrary to regulatory requirements. To avoid concerns
about whether RINs assigned to batches have not been appropriately
transferred with the batch, we request comment on whether PTDs should
include some notation indicating that the assigned RIN has been
removed.
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 may not be captured.
This would include such renewable fuels as neat biodiesel (B100),
methanol for use in a dedicated methanol vehicle, biogas for use in a
CNG vehicle, or renewable diesel used in its neat form.
As for ethanol and biodiesel, neat renewable fuels would be
assigned a RIN by the producer. However, in cases where the neat
renewable fuel is never owned by an obligated party or blended into
gasoline or diesel before being used as a motor vehicle fuel, no party
would have the right to separate the RIN from the batch. The RIN would
therefore never become available to an obligated party for RFS
compliance purposes. Although the current use of these neat renewable
fuels is minor in comparison to the volumes of ethanol and lower blend
levels of biodiesel, we nevertheless believe that they should be
allowed to help meet the volume requirements of the RFS program.
To address this issue, we propose to more broadly define the right
to separate a RIN from a batch. In addition to obligated parties and
blenders, we believe that any party holding a batch of renewable fuel
for which the RIN has not been separated could separate the RIN from
the batch 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. Given the
lack of any significant use of ethanol in its neat (but denatured) form
as a motor vehicle fuel, RINs for neat ethanol could only be separated
by an obligated party or a party that blends it with gasoline. This
would include a party that blended ethanol with a small amount of
gasoline to form E85, since there are millions of vehicles in the fleet
that can operate on E85. In this case, E85 would be treated like any
other ethanol/gasoline blend.
Under our proposed approach, therefore, any party that holds a
batch of renewable fuel that is typically used in its neat form and was
designated by the producer for use in its neat form as a motor vehicle
fuel would be given the right to separate the RIN from the batch. 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.
Biodiesel (mono alkyl esters) 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, including the
following:
To reduce impacts on fuel economy.
To mitigate cold temperature operability issues.
To market biodiesel as an additive rather than an
alternative fuel.
To address concerns of some engine owners or manufacturers
regarding the impacts of biodiesel on engine durability or drivability.
To reduce the cost of the resulting fuel.
Biodiesel 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 is occasionally used in
its neat form. However, this approach is the exception rather than the
rule. Consequently, we propose that the RIN assigned to a batch of
biodiesel could only be separated from that batch if and when the
biodiesel is blended with conventional diesel. To avoid claims that
very high concentrations of biodiesel count as a blended product, we
also propose that biodiesel must be blended into conventional diesel at
a concentration of 80 volume percent or less before the RIN can be
separated from the batch.
Our proposed approach to biodiesel would mean that biodiesel used
in its neat form would not be valid for compliance purposes under the
RFS program. To address this issue, we request comment on additionally
allowing a biodiesel producer to separate the RIN from the batch if it
could establish that it produced the batch of biodiesel specifically
for use as motor vehicle fuel in its neat form, and that the biodiesel
was in fact used in its neat form.
3. Distribution of Separated RINs
Once a RIN is separated from a batch of renewable fuel, it would
become freely transferable. Each RIN could be held by any party, and
transferred between parties any number of times. This approach would
apply to extra-value RINs (RINs generated based on Equivalence Values
greater than 1.0) as well as standard-value RINs.
We are not proposing to limit the number of times that a RIN could
be transferred, nor the types of parties that could receive or transfer
RINs. However, this approach would be unique among EPA's fuel
regulations. For all previous motor vehicle fuel credit trading
programs we have allowed only refiners and importers to transfer
credits, and have limited the number of times credits could be
transferred to one or two
[[Page 55591]]
transfers. This includes, for example, the credit trading programs for
reformulated gasoline and gasoline sulfur. These limitations were
included to make the credit trading programs enforceable by making the
transfer of credits, from the credit generator to the credit user,
shorter, and populated only by the refiners and importers who were
obligated to meet those standards. These approaches also helped to
ensure the validity of credits by limiting the sources of credits to
companies that the obligated parties know to be reliable business
partners. A recent report provided to the Agency by the American
Petroleum institute also provides support for limiting RIN trading to
obligated parties.\35\ Therefore, we are seeking comment on limiting
the number of trades and limiting the trades to only occur between
obligated parties even though we are not proposing to do so here.
---------------------------------------------------------------------------
\35\ Montgomery, David W., ``Recommendations for a Trading
Program Which Will Comply with the Renewable Fuel Standard,'' CRA
International, Inc. May 25, 2006.
---------------------------------------------------------------------------
For the RFS program, we believe that there is a need to provide for
this more open trading, and that it can occur without unduly
sacrificing the enforceability of the program or increasing its
oversight burden. As described earlier, the RFS program is unique in
that obligated parties are typically not the ones producing the
renewable fuels and generating the RINs, so there is a need for trades
to occur between obligated parties and non-obligated parties. By
prohibiting anyone except obligated parties from holding RINs after
they have been separated from a batch, we might be making it more
difficult for those RINs to eventually be transferred to the obligated
parties that need them. This is especially important in the case of the
RFS program, because the program must work efficiently not only for a
limited number of obligated parties, but a number of non-obligated
parties as well. A potentially large number of oxygenate blenders, many
of which will be small businesses, will be looking for ways to market
their RINs. Furthermore, in some cases renewable fuel producers will
also have RINs (in particular, extra-value RINs) that can be marketed.
Allowing other parties, including brokers, to receive 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.
We believe we can ensure the enforceability of the program despite
opening up trading to non-obligated parties and allowing multiple
trades. The RIN number, along with the associated electronic reporting
mechanism, should allow 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 would be straightforward. The
number of RIN trades, and the parties between whom the RINs are being
traded, would only have the effect of increasing the size of the
database.
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. would be at the discretion of the
parties involved. The Agency would be 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 would therefore be the subject of various
recordkeeping and reporting requirements as described in Section IV,
and these requirements would generally apply regardless of whether RIN
has been separated from a batch.
The means through which RIN trades would occur would also be at the
discretion of the parties involved. For instance, parties with RINs
could create open auctions, contract directly with those obligated
parties who seek RINs, use brokers to identify potential transferees
and negotiate terms, or just transfer the RINs to any other willing
party. Brokers involved in RIN transfer could either operate in the
role of arbitrator without holding the RINs, or alternatively could
receive the RINs from one party and transfer them to another. If they
are the transferee of any RINs, they would also be subject to the
registration, recordkeeping, and reporting requirements. We do not
believe that it would be appropriate or useful for the EPA to become
directly involved in RIN transfers, other than in the role of providing
a database within which transfers can be recorded. Thus EPA would not
plan on establishing a clearinghouse or centralized brokerage for the
management of RIN transfers, nor contract with a private firm through
whom all RIN buyers and sellers would arrange transfers. Our experience
with other credit trading programs suggests that, left to themselves,
natural free-market mechanisms will arise to handle RIN transfers, and
that these mechanisms will maximize the efficiency of the market while
minimizing the transaction costs for transfers of RINs.
4. Alternative Approaches to RIN Distribution
During the development of our proposed RFS trading and compliance
program, stakeholders offered a variety of alternative program design
approaches. Most of these alternatives recognize the value of a RIN-
based system of compliance, but they differ in terms of which parties
would be allowed to separate a RIN from a batch and the means through
which the RINs should be transferred to obligated parties. We invite
comment on all of these options.
Our primary concern with the alternative approaches is that we
believe they would be less effective than our proposed program at
ensuring that RINs would get to the obligated parties who need them in
a timely fashion. As described above, stakeholders have expressed
serious concerns about any program structure that could allow non-
obligated parties to exercise market power in the RIN market, and the
program we are proposing today is designed to minimize these concerns.
The alternative approaches described below, in contrast, could
potentially allow some non-obligated parties who acquire RINs to either
refuse to transfer them, make them difficult for obligated parties to
obtain, or drive their price up by exercising market power. We believe
that these stakeholder concerns about alternative program options are
legitimate, given that nearly half of the production volumes of ethanol
come from only seven companies and only five companies manage the
majority of ethanol marketing. Our proposal also best addresses other
related issues, such as limiting the number of obligated parties,
providing for the most open RIN market, and providing an effective
means at ensuring RIN certainty.
a. Producer With Direct Transfer of RINs. One alternative to our
proposed program would allow producers and importers of renewable fuels
to transfer RINs separately from the renewable fuel that they
represent. The producer or importer would still generate the RIN, but
would not necessarily need to assign it to a specific batch of
renewable fuel. The producer or importer would be required to transfer
the RIN, but only to an obligated party.
Under this approach non-obligated parties other than producers and
importers would have no RIN ownership opportunities and would therefore
not bear any burden associated with transferring RINs with batches.
[[Page 55592]]
This would eliminate most of the recordkeeping and reporting
requirements applicable to them under our proposed program. There would
also be no need for any regulatory requirements to ensure proper
accounting of RINs as they move through the distribution system, such
as requirements necessary to address volume changes due to temperature,
batch splits and mergers, use of renewable fuels in their neat form,
and the recordkeeping and reporting associated with these requirements.
The challenges associated with this approach, however, pertain to
the disconnect between RINs and batches of renewable fuel. For
instance, the disconnect would produce the possibility for the creation
of market power with the renewable fuel producer that generates the
RINs. As discussed above, there is the possibility that renewable
producers might not place all RINs on the market for procurement by the
obligated parties, thereby driving up their price and/or increasing
further the demand for renewables. It is very unlikely that they would
withhold renewable fuel itself from the market in order to drive up the
price for it. Not only is storage capacity limited, but there is no
evidence that ethanol producers or marketers have ever exercised this
type of market control. This is also true under our proposed program.
In addition, although a refiner could purchase renewable fuel
directly from a producer and acquire RINs at the same time, there would
be many other cases in which a refiner would purchase renewable fuel
without RINs (such as from a marketer). Although the market would
likely develop in such a way that renewable fuel without RINs would be
priced differently than renewable fuels with RINs, the purchase of the
renewable fuel would still have no bearing on the refiner's RFS
compliance demonstration, contrary to the intent of the Act. The
refiner would have to procure RINs separately. If the refiner purchased
more renewable fuel than it needed for compliance purposes in this way,
it would not have any excess RINs to transfer to another party. The Act
stipulates that allowances must be made for credits to be generated for
excess renewable fuel.
To address the concern regarding producers withholding RINs from
the market, under this alternative the renewable producer would be
required to make the RINs available for transfer to an obligated party.
As under the proposed option, this RIN transfer could be done in one of
several ways, such as through direct contract or a restricted
clearinghouse. Any RINs not provided directly to an obligated party
would then need to be made available through a regularly scheduled
public auction to the highest bidder. This could be through an existing
internet auction Web site, or through another auction mechanism
implemented by a generator so long as the mechanism is equally open and
available to all obligated parties. Only obligated parties would be
permitted to bid on the RINs in such an auction.
To ensure the effectiveness of such an approach, however, there are
a number of additional aspects of the program that would need to be
specified. Since a renewable producer could essentially withhold RINs
from the market by setting the selling price too high, such an approach
would hinge upon any such auctions occurring without any minimum price
for the RINs. Producers would be required to transfer RINs to the
highest bidder regardless of the bid price, even if there was only a
single bidder. The renewable producer would be required to send the
successful bidder a written confirmation of the RIN transfer, including
the RIN identification numbers. If there were no bids, the renewable
producer would be required to roll them over to subsequent auction
cycles until such time as the RINs were no longer valid for compliance
purposes and they would simply be retired. Finally, in order to ensure
that RINs were actually being made available, such sales, trades, or
auctions would be required to occur at least quarterly, but we seek
comment on whether a shorter cycle would be more appropriate.
Various other aspects of the RIN auctions or transactions would
also have to be specified. For example, the location, time, and other
details of any auction would have to be made widely known to obligated
parties in sufficient time for them to participate. To this end, the
rule could specify that there must be advance public notice of the
intent to conduct an auction and the auction procedures, and that this
notice must be advertised through nationwide media or a public Internet
posting. The minimum amount of advance notice could be, for example,
one week or four weeks. The regulations could require that the RINs be
transferred in large enough blocks, such as 5,000 RINs, in order to
prevent undue transaction costs. The regulations could also specify the
time period during which any public auction must remain open; seven
days could be specified, for example. Other criteria for how the
auction is conducted could be included in order to ensure its
legitimacy. Interested commenters should include details for RIN
auctions or transactions that they believe should be addressed in
implementing regulations.
Our proposed program is designed to ensure that the existing market
mechanisms for the distribution of renewable fuel can be used for the
distribution of RINs as well. The need for independent RIN markets is
minimized, and likewise the regulatory oversight of such markets is
minimized. Under the direct transfer alternative described above,
however, not only does an independent RIN market become a central
feature of the RFS program, but the regulations might need to specify
the many various aspects of RIN transfers as described above, and doing
so would represent an intervention into the market that the Agency has
not exercised before. It may be necessary to design the regulatory
provisions in this way in order to have an enforceable program under
this alternative, but we would have to be convinced that such an
approach could be properly structured and that it was superior to other
alternatives.
Under this option, non-obligated parties such as marketers or
brokers would not be allowed to own RINs. It could be possible to add
in this flexibility, but in effect this option would then operate
similarly to our proposed approach, but with additional complications
and transaction costs due to the fact RINs would not follow batches
through the distribution system. Therefore, we do not believe it is
appropriate to provide this flexibility as part of the direct-transfer
option.
b. Producer With Open RIN Market. Another approach would allow
producers and importers of renewable fuels to transfer RINs separately
from the renewable fuel to any party. If a renewable fuel producer did
choose to transfer the RIN with the batch, any downstream party would
have the right to separate that RIN from the batch.
Although we believe that the recordkeeping burden placed upon
marketers and distributors under our proposed program would be minimal,
this alternative approach would essentially eliminate that burden
altogether. Marketers and distributors would not have to ensure that
RINs were transferred with batches and keep a record of those
transfers, and would not be responsible for ensuring that RINs remain
assigned to batches during batch splits and mergers. Any marketer or
distributor that did receive a batch with an assigned RIN could
separate the RIN from the batch and transfer it, maximizing the choices
available to them.
[[Page 55593]]
However, this alternative approach would increase the burdens for
obligated parties to comply with their renewable fuel obligation since
all RINs would be controlled by producers and marketers at the point of
generation. The concerns described above regarding the exercising of
market power in the RIN market by a small number of non-obligated
parties would apply to this alternative. Although these concerns may be
less significant under EIA's current projections that renewable fuel
production volumes will exceed the RFS program requirements, we believe
that we should design the RFS program to function smoothly under any
future market scenario. Since it is possible that the market conditions
leading to EIA's projections could change, we believe that the concern
about producers and marketers exercising market power in the RIN market
is important. As a result, we do not believe that this alternative
approach is most appropriate.
c. First Purchaser. As under our proposed approach, in this
alternative the renewable fuel producer would be required to assign a
RIN to every batch of renewable fuel and to transfer that RIN with the
batch. However, the first party in the distribution system to take
ownership of the batch would have the right to separate the RIN from
the batch. This means that any non-obligated party that purchased the
renewable fuel from its producer would be able to separate the RIN and
to transfer it independently from the batch.
The advantage of this alternative approach, as compared to our
proposal, is that it would remove control of the sale of RINs from the
producers. However, the concern raised by refiners about the exercise
of market power in the RIN market remains because only five companies
today manage the majority of ethanol marketing in the U.S. With such a
small number of companies, any one could exert a controlling influence
on the RIN market. In addition, many large producers operate as
marketers for other smaller producers, allowing some producers to be
the first purchaser. As discussed for the previous alternative, we
believe that we should design the RFS program to function smoothly
under any future market scenario, including ones different from those
forming the basis of the current EIA projections. Thus we believe that
the concern about marketers exercising market power in the RIN market
is still important, and as a result we do not believe that the first
purchaser approach offers significant advantages over our proposed
program.
d. Owner at Time of Blending. An alternative approach to our
proposed option of allowing obligated parties to separate RINs as soon
as they gain ownership would prohibit all parties from separating a RIN
from a batch of renewable fuel until the batch had actually been
blended into gasoline or diesel. The obligated party could retain the
RIN as soon as it gained ownership of the batch, but could not transfer
the RIN or use it for compliance purposes until the renewable fuel that
it represented was actually blended into gasoline or diesel. Thus, a
RIN could be separated from the batch of renewable fuel to which it has
been assigned only at the time of blending, and whomever owns the batch
at the time of blending would also have the right to separate the RIN
and use or transfer it.
Although we based our proposed program design on the expectation
that all renewable fuels will eventually be consumed as fuel, primarily
through blending with conventional gasoline or diesel, this alternative
approach would provide direct verification of blending. However, we do
not believe that this is necessary in order to provide an enforceable
program, and in fact it would create an additional and unnecessary
burden for blenders.
As discussed in Section III.D, it is not necessary to track
renewable fuels all the way to the point of blending because we can
confidently treat production volumes as an accurate surrogate for
consumption. This fact provides the basis for our proposed program, and
could also be used in support of the alternatives described previously.
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 proposed program.
By requiring refiners to wait until renewable fuel is blended
before they can separate the RIN, this 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, we do not believe that this represents an
advantage to this alternative since it could not occur under our
proposed program either. There are no geographic limitations to RIN
transfers within the 48 contiguous states, so obligated parties that
need RINs can purchase them from any refiner who has an excess. 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, thereby demanding an
unreasonably high price for them.
For these reasons, we do not believe that requiring renewable fuel
to be blended into gasoline or diesel before a RIN could be separated
from the batch would provide any significant advantages over our
proposed program. However, we request comment on this alternative
approach.
e. Blender at Time of Blending. Although we have concluded that
production volumes are an accurate surrogate for consumption, thus
eliminating the need to measure renewable fuel volumes at the point of
blending into gasoline or diesel, an alternative approach would do just
that.
In this alternative program approach, RINs would not be generated
by the producer of the renewable fuel and assigned to batches. Instead,
blenders would keep detailed records of the volumes of renewable fuel
that they blended into gasoline or diesel, and would generate credits
for those volumes. Blenders would be considered obligated parties, but
their obligation would be considered as zero percent to avoid redundant
obligations (i.e., to avoid the blender being responsible for blending
renewable fuel into gasoline for which a refiner or importer also has
an RFS program responsibility). Thus they would generate credits which
could then be sold to a refiner or importer who needs it for compliance
purposes.
The blender approach would differ from our proposed program and all
the other alternative approaches in that it would be based on actual
blending activity, as compared to ownership of the renewable fuel.
Under this alternative approach, the blender would not use records of
batch ownership to establish generation of credits, but rather would be
required to demonstrate that it had actually blended the renewable fuel
into gasoline or diesel. Since the blender was responsible for
blending, the blender would generate the credits from that blending and
would have the right to transfer them to another party.
Although blenders could use IRS fuel credit forms to verify the
volumes of ethanol blended into gasoline under this alternative, the
IRS forms would not provide useful information related to biodiesel or
other renewable fuels that are blended into conventional gasoline
[[Page 55594]]
or diesel.\36\ Alternative approaches to verifying that these other
renewable fuels were actually blended would therefore need to be
designed under this alternative, and these verifications would
necessarily involve additional recordkeeping and reporting
requirements.
---------------------------------------------------------------------------
\36\ There is some evidence that biodiesel producers are
operating as blenders in order to claim the right to the Federal
excise tax credit for biodiesel. However, in these cases they often
blend only very small amounts of conventional diesel into biodiesel,
such as 0.1 volume percent. The mixture, identified as B99.9, is
then transported to another blender who often adds significant
additional quantities of conventional diesel to make blends such as
B2 or B20.
---------------------------------------------------------------------------
This approach would also tend to increase the burdens on refiners
to gain access to credits and thus demonstrate compliance. A refiner
who took ownership of a batch of renewable fuel could not use that
batch to meet its RVO unless he blended it into gasoline or diesel
himself. Such circumstances would create additional complexity for the
obligated parties that are avoided by the more streamlined approach we
are proposing.
A blender approach would also be difficult to implement. To begin
with, many blenders are small businesses, and none have been
substantially regulated in an EPA fuel program before. We would be
imposing upon these parties the primary enforcement burden associated
with the RFS program even though they are not obligated for meeting the
renewable fuel standard. Also, this approach would not be able to
distinguish between cellulosic biomass ethanol and ethanol made from
other feedstocks, which creates significant difficulties in meeting
program requirements.
Under a blender approach, even accurate records of blending would
be difficult to verify. There are more than 1200 blenders in the U.S.
who blend ethanol into gasoline, in addition to those that blend
biodiesel into conventional diesel fuel. Thus the blender approach
would maximize the number of parties involved, overly complicating the
compliance system. The enforcement burden on the Agency would be
significant, and ultimately it would be likely that many claims of
blending would go unchecked.
Some of the concerns raised above could be addressed by re-
introducing the RIN concept into a blender approach. For instance, the
existence of RINs could help identify cellulosic biomass ethanol as
such. However, if a RIN-based system were implemented, this alternative
approach would become very similar to our proposed program, but with
additional enforcement burdens placed upon blenders. As a result the
advantages of this alternative approach over our proposed program would
disappear.
Due to the additional and unnecessary recordkeeping and reporting
burdens that would be placed upon blenders under this alternative, the
dissociation of credits from renewable fuels acquired by obligated
partiers, and the likelihood that many blending events may go
unchecked, we do not believe that the alternative blender approach
should be adopted.
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. We are proposing to utilize the same basic forms for registration
that we use under the reformulated gasoline (RFG) and anti-dumping
program.\37\ These forms are well known in the regulated community and
are simple to fill out. Information requested includes company and
facility names and addresses and the identification of a contact person
with phone number and e-mail address. Registrations do not expire and
upon receipt of a completed registration form, EPA will issue unique
company and facility identification numbers that will appear in
compliance reports and, in the case of renewable fuels producers, will
be incorporated in the unique RINs they generate for each batch of
renewable fuel. We intend to use the same simplified registration
method we use for existing fuels programs under 40 CFR part 80, and
parties who have already registered with EPA under an existing fuels
program will not be required to re-register and will be able to use
their existing EPA-issued company and facility registration numbers.
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\37\ Please refer to http://www.epa.gov/otaq/regs/fuels/rfgforms.htm. The relevant registration forms for our existing fuels
programs are 3520-20A, 3520-20B, and 3520-20B1. Interested parties
may wish to view these forms, as they may be useful in preparing
comments on this proposed rule.
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We plan to use a simplified method of reporting via the Agency's
Central Data Exchange (CDX). CDX will permit us to accept reports that
are electronically signed and certified by the submitter in a secure
and robustly encrypted fashion. Guidance for reporting will be issued
prior to implementation and will contain specific instructions and
formats consistent with provisions in the final rule. We intend to
accept electronic reports generated in virtually all commercially
available spreadsheet programs and to permit parties to submit reports
in comma delimited text, which can be generated with a variety of basic
software packages. 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 included in a compliance database
managed by EPA's Office of Transportation and Air Quality and will be
reviewed for completeness and for potential violations. Potential
violations will be referred to enforcement personnel.
Records related to RIN transactions may be kept in any format and
the period of record retention by reporting parties is five (5) years,
which is the time frame for retention under similar 40 CFR part 80
fuels compliance reporting programs. Records retained would include
copies of all compliance reports submitted to EPA and copies of product
transfer documents (PTDs). Records would have to be provided to the
Administrator or the Administrator's representative upon request and
they may have to be converted to a readable, usable format.
B. Requirements for Obligated Parties and Exporters of Renewable Fuels
1. Registration
We are proposing that ``obligated parties'' including refiners,
importers, and blenders of gasoline, as well as exporters of renewable
fuel, must register with EPA by [90 DAYS AFTER FINAL PUBLICATION OF THE
FINAL RULE]. Most refiners and importers are already registered with us
under various regulations related to reformulated (RFG) and
conventional gasoline or diesel fuel. We propose that these existing
registrations be applicable under the renewable fuel standard as well.
Exporters of renewable fuels may not have registered with EPA and we
anticipate perhaps 25 new registrations and 25 updated registrations
because of this program. If a party becomes subject to this proposed
regulation after the effective date, then we propose that they must
register with us and receive their EPA-issued company and facility
registration numbers prior to engaging in any transaction involving
RINs.
Any party who is not currently registered with us would have to
submit a simple registration form. We will issue a 4-digit company
identification number and, for each facility registered, a 5-digit
facility identification number. Currently registered parties will only
be
[[Page 55595]]
responsible for updating company and facility records as the need to
update routine information arises, for example, if corporate points of
contact or addresses change. Currently registered refiners and
importers would continue to use their existing 4-digit company and 5-
digit facility identification numbers.
2. Reporting
There are three types of reports that would be required of
obligated parties and exporters of renewable fuel. Reports would be
required to be submitted on an annual basis by the February 28
following a given January through December annual compliance period.
The first type of report would provide the compliance
demonstration. It would require obligated parties to provide
information about their annual volume of gasoline produced or imported,
and would require exporters to provide information about their annual
volume of renewable fuel exported. The report would also describe the
calculation of their corresponding renewable volume obligation (RVO), a
listing of the RINs applied towards the RVO, any deficit carried over
from the previous year, and any deficit carried into the next year.
The second type of report would provide detailed transactional
information regarding RINs. It would be akin to credit trading reports
submitted by refiners and importers under other fuels programs in 40
CFR part 80, such as the gasoline sulfur program. The purpose of this
report would be to document the ownership, transfer and use of RINs and
to track expired RINs. As such, and noted below, these reports would be
required of any party that owns RINs during the compliance period
covered by the report. The transactional report is necessary because
compliance with the RVO is primarily demonstrated through self-
reporting of RIN trades and therefore it is necessary for Agency
personnel to 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. Because the use of RINs
permits great flexibility in meeting the RVO, we believe that obligated
parties and others who create and handle RINs (including brokers) will
benefit from self-reporting.
The third type of report will summarize RIN activities for the
previous year and will include the total number of RINs owned, used for
compliance, transferred and expired. This report would not include
details of every RIN owned or used, since this information would be
included in the compliance and transactional reports. Instead, this
third report would simply summarize the total number of RINs falling
into different categories.
All reports submitted to us would have to be signed and certified
as true and correct by a responsible corporate officer. This can be
done electronically. As discussed above, we plan to utilize a highly
simplified electronic method of reporting via the Agency's Central Data
Exchange that is secure, provides encryption and reliable electronic
signatures, and that permits us to accept reports in the submitter's
choice of simple comma delimited text or commercially available
spreadsheet packages.
We are proposing annual reporting only. However, we encourage
comments related to the frequency of reporting. We are particularly
interested in comments related to the frequency of transactional
reports related to RINs and whether these reports should be submitted
quarterly rather than annually. We also request comment on our proposed
requirement that three distinct types of reports be submitted for each
calendar year, specifically whether these reports could be simplified
or whether a smaller number of reports could provide the same
information.
3. Recordkeeping
The proposed recordkeeping requirements for obligated parties and
exporters of renewable fuel support the enforcement of the use of RINs
for compliance purposes. Product transfer documents (PTDs) are central
to tracking individual RINs through the fungible distribution system
when those RINs are assigned to batches of renewable fuel. PTDs are
customarily issued in the course of business (i.e., issuing them is a
``customary business practice'') and are familiar to parties who
transfer or receive fuel. As with other fuels programs, PTDs may take
many forms, including bills of lading, as long as they travel with the
volume of renewable fuel being transferred. Specifically, we propose
that on each occasion any person transfers ownership of renewable fuels
subject to this proposed regulation that they provide the transferee
documents identifying the renewable fuel and containing identifying
information including the name and address of the transferor and
transferee, the EPA-issued company and facility IDs of the transferor
and transferee, the volume of renewable fuel that is being transferred,
the location of the renewable fuel at the time of transfer, and the
unique RIN associated with the volume of fuel being transferred, if
any. PTDs are used by all parties in the distribution chain down to the
retail outlet or wholesale purchaser-consumer facility that dispenses
it into motor vehicles.
Except for transfers to truck carriers, retailers or wholesale
purchaser-consumers, product codes describing various attributes of the
fuel may be used to convey the information required for PTDs, as long
as the codes are clearly understood by each transferee. Therefore,
refiners and importers and exporters of renewable fuel may use codes.
The RIN would always have to appear on each PTD in its entirety before
it is separated from a batch, since it is a unique identification
number and cannot be summarized by a shorter code.
Obligated parties and exporters of renewable fuel would have to
keep copies of PTDs and of all compliance reports submitted to EPA for
a period of not less than five (5) years. The five year period is
common to all our 40 CFR part 80 programs and is a reasonable period to
retain records in the event a potential violation is reported and must
be investigated and pursued by enforcement personnel. They would also
have to keep information related to the sale, purchase, brokering and
trading of RINs that support the information they report to EPA.
Refiners and importers would be responsible for providing records to
the Administrator or the Administrator's authorized representative in a
usable format upon request.
C. Requirements for Producers and Importers of Renewable Fuel
1. Registration
We propose that any producer or importer of renewable fuel must
register by [90 DAYS AFTER THE DATE OF FINAL PUBLICATION OF THE FINAL
RULE]. The registration requirements are the same as those for refiners
and importers of gasoline, as described above. Renewable fuel producers
were not previously required to register with EPA and we anticipate
around 280 new registrants as a result of this proposed registration
requirement. Although renewable fuels producers are not ``obligated
parties,'' they are the parties who generate RINs. As mentioned above
in IV.B.1, the EPA-issued registration numbers will be part of the
unique RIN generated by the producer or importer of renewable fuel. In
order to support effective recordkeeping and reporting
[[Page 55596]]
for compliance purposes, we believe it is necessary for them and any
party who generates or owns RINs to register with the Agency.
Registration is a simple process and there is no expiration date
associated with a registration. However, registration information may
be updated by the registrant as needed, for example, if a mailing
address changes. The information collected includes company name and
address; facility name(s) and address(es); and a contact person's name,
phone number and e-mail address. Any party who is not currently
registered with us would have to submit registration forms. We will
issue a 4-digit company identification number and, for each facility
registered, a 5-digit facility identification number. If a party
becomes subject to this proposed regulation after the effective date,
then we propose that they must register with us and receive their EPA-
issued company and facility identification numbers prior to generating
or holding any RINs.
We also propose that small volume domestic producers of renewable
fuels, those who produce less than 10,000 gallons per year, be allowed
to remain unregistered. This proposed provision would free them from
recordkeeping and reporting requirements, but it would also preclude
them from generating RINs.
2. Reporting
Renewable fuel producers and importers would be required to submit
three different annual reports by February 28, reflecting activity
during the previous calendar year. The first report would be an annual
report that reflects the generation of RINs. This report would identify
each batch of renewable fuel produced or imported during the previous
year and the RINs generated for each batch. This annual report would
provide information about the production date, renewable fuel type and
volume of renewable fuel produced or imported. For specific information
about how RINs are actually generated, please refer to the discussion
in Section III.D.2 of this preamble.
Like any of the parties who can own RINs, a renewable fuel producer
would also have to submit a second type of report detailing
transactional information regarding RINs. This report would list the
RINs which they own at the end of the reporting period as well as any
RINs they have acquired from other parties or have transferred to other
parties, identifying which parties took part in the transfer. This
report would be similar to the transaction report described below
required of RIN owners who are not obligated parties, exporters, or
producers of renewable fuels.
Finally, each producer or importer of renewable fuel would be
required to submit a third annual report summarizing RIN activities for
the previous year. This report would include the total number of RINs
generated, owned, transferred, and expired.
All reports would have to be signed and certified as true and
correct by a responsible corporate officer. This can be done
electronically. As discussed above, we plan to utilize a highly
simplified electronic method of reporting via the Agency's Central Data
Exchange that is secure, provides encryption and reliable electronic
signatures, and that permits generation of reports in the submitter's
choice of simple comma delimited text or commercially available
spreadsheet packages.
We request comment on our proposed requirement that three distinct
types of reports be submitted for each calendar year, specifically
whether these reports could be simplified or whether a smaller number
of reports could provide the same information.
3. Recordkeeping
The proposed recordkeeping requirements for renewable fuels
producers support the enforcement of the use of RINs for compliance
purposes. Product transfer documents (PTDs) are central to tracking
individual RINs through the fungible distribution system when those
RINs are assigned to batches of renewable fuel. PTDs are customarily
generated and issued in the course of business (i.e. issuing them is a
``customary business practice'') and are familiar to parties who
transfer or receive fuel. As with other fuels programs, PTDs may take
many forms, including bills of lading, as long as they travel with the
volume of renewable fuel being transferred. Specifically, we propose
that on each occasion any person transfers ownership of renewable fuels
subject to this proposed regulation that they provide the transferee
documents identifying the renewable fuel and containing identifying
information including the name and address of the transferor and
transferee, the EPA-issued company and facility IDs of the transferor
and transferee, the volume of renewable fuel that is being transferred,
the location of the renewable fuel at the time of transfer, and the
unique RIN associated with the volume of fuel being transferred, if
any. PTDs are used by all parties in the distribution chain down to the
retail outlet or wholesale purchaser-consumer facility that dispenses
it into motor vehicles.
Except for transfers to truck carriers, retailers or wholesale
purchaser-consumers, product codes may be used to convey the
information required for PTDs, as long as the codes are clearly
understood by each transferee. Therefore, renewable fuels producers may
use codes. The RIN would always have to appear on each PTD in its
entirety before it was separated from the batch, since it is a unique
identification number and cannot be summarized by a shorter code.
Renewable fuels producers would have to keep copies of PTDs and of
all compliance reports submitted to EPA for a period of not less than
five (5) years. They would also have to keep information related to the
sale, purchase, brokering and trading of RINs. Upon request, renewable
fuels producers or importers would be responsible for providing
documentation of PTDs to the Administrator or the Administrator's
authorized representative in a usable format.
D. Requirements for Other Parties Who Own RINs
1. Registration
We propose that other parties who intend to own RINs, and who are
not obligated parties, exporters of renewable fuels, or renewable fuels
producers or importers, must also register before ownership of any RINs
is assumed. The registration requirements are the same as those for
other parties discussed previously in Sections IV.B.1 and IV.C.1 above,
and require the registrant to provide very basic information about the
company, its facility or facilities, and a contact person. The
registration is on very simple forms provided by EPA. A variety of
parties may own RINs including (but certainly not limited to)
marketers, blenders, terminal operators, and jobbers. (As is mentioned
in the previous two sections, obligated parties and renewable producers
may also own RINs but have other reporting responsibilities, as well.)
It is possible to own RINs separately from batches of renewable
fuel. For example, a broker might be expected to own RINs in this
fashion. Any party who is not currently registered with us and who
intends to own RINs would have to submit a simple registration form, as
described above. We anticipate about 1,500 new registrants as a result
of this proposed registration requirement, although an exact estimation
of the number of parties that will constitute this group is difficult
to
[[Page 55597]]
make. As with the other parties described in this Section, we will
issue a 4-digit company identification number and, for each facility
registered, a 5-digit facility identification number. If a party
becomes subject to this proposed regulation after the effective date,
then we propose that they must register with us and receive their EPA-
issued company and facility identification numbers prior to owning any
RINs.
2. Reporting
Parties who own RINs would be required to submit two types of
annual reports by February 28, representing activity in the previous
calendar year. The first report would document RIN transactions. This
report is akin to the credit trading reports submitted by refiners and
importers under other fuels programs in 40 CFR part 80 and is the same
as the second report described for obligated parties in some detail in
Section IV.B.2 above.
The second type of report would summarize RIN activities for the
previous year, including the total number of RINs owned, transferred,
and expired. This report would not include details of every RIN owned
or used, since this information would be included in the transactional
report. Instead, this report would simply summarize the total number of
RINs falling into different categories.
All reports would have to be signed and certified as true and
correct by a responsible corporate officer. This can be done
electronically. As discussed above, we plan to utilize a highly
simplified electronic method of reporting via the Agency's Central
Data.
As discussed above, we are seeking comments on the frequency of
reporting, especially with regard to RIN transactions. We are proposing
annual reporting, but are seeking comments on whether reporting should
be quarterly.
We also request comment on our proposed requirement that two
distinct types of reports be submitted for each calendar year,
specifically whether these reports could be simplified or whether a
smaller number of reports could provide the same information.
3. Recordkeeping
The proposed recordkeeping requirements for parties who own RINs
support the enforcement of the use of RINs for compliance purposes.
Product transfer documents (PTDs) are central to tracking individual
RINs through the fungible distribution system when those RINs are
assigned to batches of renewable fuel. PTDs are customarily generated
and issued in the course of business (i.e., issuing them is a
``customary business practice'') and are familiar to parties who
transfer or receive fuel. As with other fuels programs, PTDs may take
many forms, including bills of lading, as long as they travel with the
volume of renewable fuel being transferred. Specifically, we propose
that on each occasion any person transfers ownership of RINs (whether
assigned to batches of renewable fuel or not) that they provide the
transferee documents identifying the RIN and containing identifying
information including the name and address of the transferor and
transferee, the EPA-issued company and facility IDs of the transferor
and transferee, and the unique RINs that are being transferred.
Typically, parties who own RINs connected with batches of fuel would
handle PTDs; however, parties who own RINs separate from batches may
not. A party who owns RINs in connection with fuel and who received a
PTD would be responsible for meeting requirements related to PTDs.
Parties who own RINs but who are not obligated parties, exporters
of renewable fuel, or renewable fuel producers or importers would have
to keep copies of PTDs associated with RIN transfers and of all
compliance reports submitted to EPA for a period of not less than five
(5) years. They would also have to keep information related to the
sale, purchase, brokering and trading of RINs. Upon request, owners of
RINs would be responsible for providing records to the Administrator or
the Administrator's authorized representative in a usable format.
V. What Acts Are Prohibited and Who Is Liable for Violations?
The prohibition and liability provisions applicable to this
proposed RFS program would be similar to those of other gasoline
programs. The proposed 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 that is not
assigned a proper RIN, creating or transferring invalid RINs, or
transferring RINs that are not identified by proper RIN numbers. Any
person subject to a prohibition would be held liable for violating that
prohibition. Thus, for example, an obligated party would be liable if
the party failed to acquire sufficient RINs to meet its RVO. A party
who produces or imports renewable fuels would be liable for a failure
to assign proper RINs to batches of renewable fuel produced or
imported. Any party, including an obligated party, would be liable for
transferring a RIN that was not properly identified.
In addition, any person who is subject to an affirmative
requirement under the RFS program would be liable for a failure to
comply with the requirement. For example, an obligated party would be
liable for a failure to comply with the annual compliance reporting
requirements. A renewable fuel producer or importer would be liable for
a failure to comply with the applicable batch reporting requirements.
Any party subject to recordkeeping or product transfer document
requirements would be liable for a failure to comply with these
requirements. Like other EPA fuels programs, the proposed rule provides
that a party who causes another party to violate a prohibition or fail
to comply with a requirement may be found liable for the violation.
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).\38\ Accordingly, under
the proposed 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 proposed rule, a
failure to acquire sufficient RINs to meet a party's renewable fuels
obligation would constitute a separate day of violation for each day
the violation occurred during the annual averaging period.
---------------------------------------------------------------------------
\38\ Sec. 1501(b) of the Energy Policy Act of 2005.
---------------------------------------------------------------------------
As discussed above and in Section III.D, the regulations would
prohibit any party from creating or transferring invalid RINs. These
invalid RIN provisions would apply regardless of the good faith belief
of a party that the RINs were 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
would address the consequences if an obligated party was found to have
used invalid RINs to demonstrate compliance with its RVO. In this
situation, the refiner or importer that used the invalid RINs would be
required to deduct any invalid RINs from its compliance calculations.
The refiner or importer would be liable for violating the standard if
the remaining number of valid RINs was insufficient to meet its RVO,
and the obligated party might be subject to monetary penalties if it
used invalid RINs in its compliance demonstration. In determining what
penalty is appropriate, if any, we would consider a number of factors,
including
[[Page 55598]]
whether the obligated party did in fact procure sufficient valid RINs
to cover the deficit created by the invalid RINs, and whether the
purchaser was indeed a good faith purchaser based on an investigation
of the RIN transfer. A penalty might include both the economic benefit
of using invalid RINs and/or a gravity component.
Although an obligated party would be liable under our proposed
program for a violation if it used invalid RINs for compliance
purposes, we would normally look first to the generator or seller of
the invalid RINs both for payment of penalty and to procure sufficient
valid RINs to offset the invalid RINs. However, if, for example, that
party was out of business, then attention would turn to the obligated
party who would have to obtain sufficient valid RINs to offset the
invalid RINs.
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. We request comment on whether a
presumptive liability scheme may have application under the RFS rule.
We also request comment on the need for additional prohibition and
liability provisions specific to the proposed RFS program.
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 June 2006, there were 102 ethanol production facilities
operating in the United States with a combined production capacity of
approximately 4.9 billion gallons per year.\39\ 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 93 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.
---------------------------------------------------------------------------
\39\ The June 2006 ethanol production baseline was generated
from a variety of data sources including Renewable Fuels Association
(RFA), Ethanol Biorefinery Locations (Updated June 19, 2006);
Ethanol Producer Magazine (EPM), U.S. & Canada Fuel Ethanol Plant
Map (Spring 2006); and International Fuel Quality Center (IFQC),
Special Biofuels Report 75 (April 11, 2006) as well as
ethanol producer websites. The production 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 were used to represent plant capacity, as nameplate
capacities are often underestimated.
Table VI.A.1-1.--2006 U.S. Ethanol Production by Feedstock
----------------------------------------------------------------------------------------------------------------
Capacity Percent of Number of Percent of
Plant feedstock MMGal/yr capacity plants plants
----------------------------------------------------------------------------------------------------------------
Corn a...................................................... 4,516 92.7 85 83.3
Corn/Milo................................................... 162 3.3 5 4.9
Corn/Wheat.................................................. 90 1.8 2 2.0
Corn/Barley................................................. 40 0.8 1 1.0
Milo/Wheat.................................................. 40 0.8 1 1.0
Waste Beverage b............................................ 16 0.3 5 4.9
Cheese Whey................................................. 8 0.2 2 2.0
Sugars & Starches........................................... 2 0.0 1 1.0
---------------------------------------------------
Total................................................... 4,872 100.0 102 100.0
----------------------------------------------------------------------------------------------------------------
a Includes seed corn.
b Includes brewery waste.
There are a total of 94 plants processing corn and/or other
similarly processed grains. Of these facilities, 84 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. Carbon dioxide is also produced in the process and may
be recovered as a saleable product. 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, approximately 23 percent of
the current 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 more simplistic 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 feedstocks 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 to achieve this goal, but the technologies are still
not fully developed for large-scale commercial production. As of June
2006, there were no U.S ethanol plants processing cellulosic
feedstocks. Currently, the only known cellulose-to-ethanol plant in
North America is Iogen in Canada, which produces approximately one
[[Page 55599]]
million gallons of ethanol per year from wood chips. For a more
detailed discussion on cellulosic ethanol production/technologies,
refer to Section 7.1.2 of the Draft Regulatory Impact Analysis (DRIA).
The ethanol production process is relatively resource-intensive and
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 102 ethanol production facilities, 98 burn natural gas, 2
burn coal, 1 burns coal and biomass, and 1 burns syrup from the process
to produce steam. A summary of ethanol production by plant energy
source is found below in Table VI.A.1-2.
Table VI.A.1-2.--2006 U.S. Ethanol Production by Energy Source
----------------------------------------------------------------------------------------------------------------
Capacity Percent of Number of Percent of
Energy source MMGal/yr capacity plants plants
----------------------------------------------------------------------------------------------------------------
Natural Gas \a\............................................. 4,671 95.9 98 96.1
Coal........................................................ 102 2.1 2 2.0
Coal & Biomass.............................................. 50 1.0 1 1.0
Syrup....................................................... 49 1.0 1 1.0
---------------------------------------------------
Total................................................... 4,872 100.0 102 100.0
----------------------------------------------------------------------------------------------------------------
\a\ Includes a natural gas facility which is considering transitioning to coal.
Currently, 7 of the 102 ethanol plants utilize co-generation or
combined heat and power (CHP) technology. CHP is a mechanism for
improving overall plant efficiency. CHP facilities produce their own
electricity (or coordinate with the local municipality) and use
otherwise-wasted exhaust gases to help heat their process, reducing the
overall demand for boiler fuel.
The majority of ethanol is produced in the Midwest within PADD 2--
not surprisingly, where most of the corn is grown. Of the 102 U.S.
ethanol production facilities, 93 are located in Midwest. The PADD 2
facilities account for about 97 percent (or 4.7 billion gallons per
year) of the total domestic ethanol production, as shown in Table
VI.A.1-3.
Table VI.A.1-3.--2006 U.S. Ethanol Production by PADD
----------------------------------------------------------------------------------------------------------------
Capacity Percent of Number of Percent of
PADD MMgal/yr capacity plants plants
----------------------------------------------------------------------------------------------------------------
PADD 1...................................................... 0.4 0.0 1 1.0
PADD 2...................................................... 4,710 96.7 93 91.2
PADD 3...................................................... 30 0.6 1 1.0
PADD 4...................................................... 98 2.0 4 3.0
PADD 5...................................................... 34 0.7 3 2.9
---------------------------------------------------
Total................................................... 4,872 100.0 102 100.0
----------------------------------------------------------------------------------------------------------------
Leading the Midwest in ethanol production are Iowa, Illinois,
Nebraska, Minnesota, and South Dakota with a combined capacity of 3.9
billion gallons per year. Together, these five states' 69 ethanol
plants account for 80 percent of the total domestic product. Although
the majority of ethanol production comes from the Midwest, there is a
sprinkling of plants situated outside the corn belt ranging from
California to Tennessee all the way down to Georgia.
The U.S. ethanol industry is currently comprised of a mixture of
corporations and farmer-owned cooperatives (co-ops). More than half
(55) 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 nearly 65 percent of the total U.S.
ethanol production capacity. Additionally, 45 percent of the total
capacity comes from 22 plants owned by just 8 different companies.
2. Expected Growth in Ethanol Production
Over the past 25 years, domestic fuel ethanol production has
steadily increased due to technological advances, environmental
regulation (e.g., oxygenate requirements in ozone and carbon monoxide
non-attainment areas), and the rising cost of crude oil. More recently,
ethanol production has soared due to state MTBE bans, steep increases
in crude oil prices, and producer tax incentives. As shown below 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.
[[Page 55600]]
[GRAPHIC] [TIFF OMITTED] TP22SE06.002
EPA forecasts ethanol production to 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, record-high
crude oil prices are expected to continue to drive up demand for
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 (4.9 billion gallons) is already exceeding the 2006
renewable fuel requirement (4.0 billion gallons). In addition, there is
another 2.5 billion gallons of ethanol production capacity currently
under construction.\40\ A summary of the new construction and expansion
projects currently underway (as of June 2006) is found in Table VI.A.2-
1.
---------------------------------------------------------------------------
\40\ Under construction plant locations, capacities, feedstocks,
and energy sources as well as planned/proposed plant locations and
capacities were derived from a variety of data sources including
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations
(Updated June 19, 2006); Ethanol Producer Magazine (EPM), U.S. &
Canada Fuel Ethanol Plant Map (Spring 2006); and International Fuel
Quality Center (IFQC), Special Biofuels Report 75 (April
11, 2006) as well as ethanol producer Web sites.
Table VI.A.2-1.--Under Construction U.S. Ethanol Plant Capacity
--------------------------------------------------------------------------------------------------------------------------------------------------------
2006 ETOH baseline New construction Plant expansions 2006 baseline + UC
------------------------------------------------------------------ \a\
---------------------
MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants
--------------------------------------------------------------------------------------------------------------------------------------------------------
PADD 1.......................................................... 0.4 1 0 0 0 0 0.4 1
PADD 2.......................................................... 4,710 93 2,048 35 252 8 7,010 128
PADD 3.......................................................... 30 1 30 1 0 0 60 2
PADD 4.......................................................... 98 4 50 1 7 1 155 5
PADD 5.......................................................... 34 3 90 2 0 0 124 5
---------------------------------------------------------------------------------------
[[Page 55601]]
Total....................................................... 4,872 102 2,218 39 259 9 7,349 141
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Under Construction.
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.
[GRAPHIC] [TIFF OMITTED] TP22SE06.003
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
December 2007), the resulting U.S. ethanol production capacity would be
over 7.3 billion gallons. Together with estimated biodiesel production
(300 million gallons by 2012), this would be more than enough renewable
fuel to satisfy the 2012 renewable fuel requirement (7.5 billion
gallons) contained in the Act. However, ethanol production is not
expected to stop here. There are more and more ethanol projects being
announced each day. Many of these potential projects are at various
stages of planning, such as conducting feasibility studies, gaining
city/county approval, applying for permits, applying for financing/
fundraising, or obtaining contractor agreements. Other projects have
been proposed or announced, but have not entered the formal planning
process. If all these plants were to come to fruition, the combined
domestic ethanol production could exceed 20 billion gallons as shown in
Table VI.A.2-2.
[[Page 55602]]
Table VI.A.2-2.--Potential U.S. Ethanol Production Projects
--------------------------------------------------------------------------------------------------------------------------------------------------------
2006 baseline + UC Planned Proposed Total ETOH potential
\a\ -----------------------------------------------------------------
-----------------------
MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants
--------------------------------------------------------------------------------------------------------------------------------------------------------
PADD 1......................................................... 0.4 1 250 3 1,005 21 1,255 25
PADD 2......................................................... 7,010 128 1,940 15 7,508 90 16,458 233
PADD 3......................................................... 60 2 108 1 599 9 767 12
PADD 4......................................................... 155 5 0 0 815 14 970 19
PADD 5......................................................... 124 5 128 2 676 18 928 25
----------------------------------------------------------------------------------------
Total...................................................... 7,349 141 2,426 21 10,603 152 20,378 314
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Under Construction.
However, although there is clearly a great potential for growth in
ethanol production, it is unlikely that all the announced projects
would actually reach completion in a reasonable amount of time. There
is no precise way to know exactly which plants would come to fruition
in the future; however, we've chosen to focus our further discussions
on only those plants which are under construction or in the final
planning stages (denoted as ``planned'' above in Table VI.A.2-2). The
distinction between ``planned'' versus ``proposed'' is that as of June
2006 planned projects had completed permitting, fundraising/financing,
and had builders assigned with definitive construction timelines
whereas proposed projects did not.
As shown in Table VI.A.2-2, once all the under construction and
planned projects are complete (by 2012 or sooner), the resulting U.S.
ethanol production capacity would be 9.8 billion gallons, exceeding the
2012 EIA demand estimate (9.6 billion gallons). This forecasted growth
would double today's production capacity and greatly exceed the 2012
renewable fuel requirement (7.5 billion gallons). In addition, domestic
ethanol production would be supplemented by imports, which are also
expected to increase in the future (as discussed in DRIA Section 1.5).
Of the 60 forecasted new ethanol plants (39 under construction and
21 planned), all would (at least initially) rely on grain-based
feedstocks. Of the plants, 56 would rely exclusively on corn as a
feedstock. As for the remaining plants: Two would rely on both corn and
milo, one would process molasses and sweet sorghum, and the last would
start off processing corn and then transition into processing bagasse,
rice hulls, and wood.
Under the Energy Act, the RFS program requires that 250 million
gallons of the renewable fuel consumed in 2013 and beyond meet the
definition of cellulosic biomass ethanol. As discussed in Section
III.B.1, 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.
Of the 60 forecasted plants, only one is expected to meet the
definition of ``cellulosic biomass ethanol'' based on feedstocks. The
planned 108 MMgal/yr facility would start off processing corn and then
transition into processing bagasse, rice hulls, and wood (cellulosic
feedstocks). It is unclear as to whether this facility would be
processing cellulosic material by 2013, however there are several other
facilities that could potentially meet the Act's definition of
cellulosic ethanol based on plant energy sources. In total, there are
seven ethanol plants that burn or plan to burn renewable feedstocks to
generate steam for their processes. As shown in Table VI.A.1-2, two
existing plants burn renewable feedstocks. One plant burns a
combination of coal and biomass and the other burns syrup from the
production process. Together these existing plants have a combined
ethanol production capacity of 99 MMgal/yr. Additionally, there are
four under construction ethanol plants which plan to burn renewable
fuels. One plant plans to burn a combination of coal and biomass, two
plants plan to rely on manure/syngas, and the other plans to start up
burning natural gas and then transition to biomass. Together these
under construction facilities have a combined ethanol production
capacity of 87 MMgal/yr. Finally, a planned 275 MMgal/yr ethanol
production facility plans to burn a combination of coal, tires, and
biomass. Depending on how much fossil fuel is displaced by these
renewable feedstocks (on a plant-by-plant basis), a portion or all of
the aforementioned ethanol production (up to 461 MMgal/yr) could
potentially qualify as ``cellulosic biomass ethanol'' under the Act.
Combined with the 108 MMgal/yr plant planning to process renewable
feedstocks, the total cellulosic potential could be as high as 569
MMgal/yr in 2013. Even if only half of this ethanol were to end up
qualifying as cellulosic biomass ethanol, it would still be more than
enough to satisfy the Act's cellulosic requirement (250 million
gallons).\41\
---------------------------------------------------------------------------
\41\ We anticipate a ramp-up in cellulosic ethanol production in
the years to come so that capacity exists to satisfy the 2013 Act's
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 \42\ and 1.9
billion gallons of MTBE \43\ were blended into gasoline to supply the
transportation sector with a total of 136 billion gallons of
gasoline.\44\ A breakdown of the 2004 gasoline and oxygenate
consumption by PADD is found below in Table VI. A.3-1.
---------------------------------------------------------------------------
\42\ EIA Monthly Energy Review, June 2006 (Table 10.1: Renewable
Energy Consumption by Source, Appendix A: Thermal Conversion
Factors).
\43\ File containing historical RFG MTBE usage obtained from EIA
representative on March 9, 2006.
\44\ EIA 2004 Petroleum Marketing Annually (Table 48: Prime
Supplier Sales Volumes of Motor Gasoline by Grade, Formulation, PAD
District, and State).
[[Page 55603]]
Table VI.A.3-1.--2004 U.S. Gasoline & Oxygenate Consumption by PADD
----------------------------------------------------------------------------------------------------------------
Ethanol MTBE \a\
PADD Gasoline ---------------------------------------------------
MMgal MMgal Percent MMgal Percent
----------------------------------------------------------------------------------------------------------------
PADD 1......................................... 49,193 660 1.34 1,360 2.76
PADD 2......................................... 38,789 1,616 4.17 1 0.00
PADD 3......................................... 20,615 79 0.38 498 2.42
PADD 4......................................... 4,542 83 1.83 0 0.00
PADD 5 \b\..................................... 7,918 209 2.63 19 0.23
California..................................... 14,836 853 5.75 0 0.00
----------------------------------------------------------------
Total...................................... 135,893 3,500 2.58 1,878 1.38
----------------------------------------------------------------------------------------------------------------
\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, not surprisingly, 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.\45\ 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.\46\
---------------------------------------------------------------------------
\45\ Based on conversation with Dean Simeroth at California Air
Resources Board (CARB).
\46\ For the purpose of this analysis, except where noted, the
term 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.\47\
---------------------------------------------------------------------------
\47\ 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 work in
progress 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
DRIA Table 2.1-4.
[[Page 55604]]
[GRAPHIC] [TIFF OMITTED] TP22SE06.004
4. Expected Growth in Ethanol Consumption
---------------------------------------------------------------------------
\48\ Total ethanol use based on EIA Monthly Energy Review, June
2006 (Table 10.1: Renewable Energy Consumption by Source, Appendix
A: Thermal Conversion Factors). MTBE use in RFG also provided by EIA
(file received from EIA representative on March 9, 2006). Reported
2004 MTBE use has been adjusted from 2.0 to 1.9 Bgal based on
assumption of timely implementation of CA, CT, and NY MTBE bans on
1/1/04 (EIA reported a slight delay and thus showed small amounts of
MTBE use in these states in 2004).
---------------------------------------------------------------------------
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 oxygenate mandate for reformulated
gasoline (RFG),\49\ all U.S. refiners are expected to eliminate the use
of MTBE in gasoline as soon as possible. In order to accomplish this
transition quickly (by 2006 or 2007 at the latest) while maintaining
gasoline volume, octane, and mobile source air toxics emission
performance standards, refiners are electing to blend ethanol into
virtually all of their RFG.\50\ This has caused a dramatic increase in
demand for ethanol which, in 2006 is being 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 dramatic rise in the price
of crude oil 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 \51\ and biodiesel use would be about 0.3 billion
gallons at a crude oil price forecast of $47 per barrel. 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. Therefore, in
assessing the impacts of expanded use of renewable fuels, 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 7.2 billion gallons of ethanol (0.25 of which was assumed to
be cellulosic) and 0.3 billion gallons of biodiesel. For the higher
projected renewable fuel consumption scenario, we assumed 9.6 billion
gallons of ethanol (0.25 of which is once again 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 these two scenarios
provide a reasonable range for analysis purposes.\52\
---------------------------------------------------------------------------
\49\ Energy Act Section 1504, promulgated on May 8, 2006 at 71
FR 26691.
\50\ Based on discussions with the refining industry.
\51\ AEO 2006 Table 17 Renewable Energy Consumption by Sector
and Source shows 0.80 quadrillion BTUs of energy coming from ethanol
in 2012. A parallel spreadsheet provided to EPA shows 2012 total
ethanol use as 628.7 thousand bbls/day (which works out to be 9.64
billion gallons/yr).
\52\ As a comparison point for cost and emissions analyses, a
2012 reference case of 3.9 billion gallons of ethanol was also
considered. The reference case is described in Section II.A.1
(above) and a complete derivation is contained in DRIA Section
2.1.3.
---------------------------------------------------------------------------
In addition to modeling two different future 2012 ethanol
consumption levels, two scenarios were considered based on how
refineries could potentially respond to the recent removal of the RFG
oxygenate mandate. In both cases, the impacted RFG areas did not change
[[Page 55605]]
from the 2004 base case.\53\ In the maximum scenario (``max-RFG''),
refineries would continue to add oxygenate (ethanol) into all batches
of reformulated gasoline. In this case, refineries currently blending
MTBE (at 11 volume percent) would be expected to replace it with
ethanol (at 10 volume percent). In the minimum scenario (``min-RFG''),
we predict some refineries would respond by using less (or even zero)
ethanol in RFG based on the minimum amount needed to meet volume,
octane, and/or total toxics performance requirements. Applying the max-
RFG and min-RFG criteria resulted in a total of four different 2012
ethanol consumption control cases:
---------------------------------------------------------------------------
\53\ For a list of the Federal RFG areas, refer to DRIA Table
2.2-1.
---------------------------------------------------------------------------
1. 7.2 billion gallons of ethanol, maximum amount used in RFG
areas;
2. 7.2 billion gallons of ethanol, minimum amount used in RFG
areas;
3. 9.6 billion gallons of ethanol, maximum amount used in RFG
areas; and
4. 9.6 billion gallons of ethanol, minimum amount used in RFG
areas.
The seasonal RFG assumptions applied in 2012 (in terms of percent
ethanol marketshare) are summarized below in Table VI.A.4-1. The
rationale behind these selected values are explained in DRIA Section
2.1.4.2.
Table VI.A.4-1.--2012 RFG Area Assumptions
------------------------------------------------------------------------
ETOH-blended gasoline (% market share) \a\
-------------------------------------------
Max-RFG scenario
RFG areas Min-RFG --------------------------------
scenario Summer Winter Summer
(percent) (percent) (percent)
------------------------------------------------------------------------
PADD 1...................... 0 100 100 100
PADD 2...................... 50 100 100 100
PADD 3...................... 0 25 100 100
California \b\.............. 25 100 100 100
Arizona \c\................. 0 100 100 100
------------------------------------------------------------------------
\a\ Percent marketshare of E10, with the exception of California (E5.7
year-round) and Arizona (E5.7 summer only).
\b\ Pertains to both Federal RFG and California Phase 3. RFG.
\c\ Pertains to Arizona Clean Burning Gasoline (CBG).
Once we determined how much ethanol was likely to be used in RFG
areas (by PADD), we systematically allocated the remaining ethanol into
conventional gasoline. First it was apportioned to winter oxy-fuel
areas. In the 2004 base case, there were 14 state-implemented winter
oxy-fuel programs in 11 states. Of these programs, 9 were required in
response to non-attainment with the CO National Ambient Air Quality
Standards (NAAQS) and 4 were implemented to maintain CO attainment
status.\54\ By 2012, 4 areas are expected to be redesignated to CO
attainment status and discontinue oxy-fuel use and 2 areas are
predicted to discontinue using oxy-fuel as a maintenance strategy.
Accordingly, a reduced amount of ethanol was allocated to oxy-fuel
areas in 2012. The remaining ethanol was distributed to conventional
gasoline (CG) in different states based on a computed ethanol margin
(rack gasoline price minus ethanol delivered price adjusted by
miscellaneous subsidies/penalties). The methodology is described in
DRIA Section 2.1.4.3.
---------------------------------------------------------------------------
\54\ Refer to DRIA Table 2.1-2.
---------------------------------------------------------------------------
The main difference in the four resulting ethanol consumption
scenarios was how far the ethanol penetrated the conventional gasoline
pool. A summary of the forecasted 2012 ethanol consumption (by control
case, fuel type and season) is found in Table VI.A.4-2.
Table VI.A.4-2.--2012 Forecasted U.S. Ethanol Consumption by Season
----------------------------------------------------------------------------------------------------------------
Ethanol consumption (MMgal)
----------------------------------------------------------------------------
2012 Control case CG OXY \a\ RFG \b\ Total
----------------------------------------------------------------------------
Summer Winter Winter Summer Winter Summer Winter
----------------------------------------------------------------------------------------------------------------
7.2 Bgal/Max-RFG................... 1,269 1,537 72 1,932 2,389 3,201 3,999
7.2 Bgal/Min-RFG................... 2,144 2,571 72 244 2,168 2,388 4,812
9.6 Bgal/Max-RFG................... 2,356 2,830 73 1,941 2,400 4,297 5,303
9.6 Bgal/Min-RFG................... 3,223 3,881 73 246 2,178 3,468 6,132
----------------------------------------------------------------------------------------------------------------
\a\ Winter oxy-fuel programs.
\b\ Federal RFG plus Ca Phase 3 RFG and Arizona CBG.
As expected, the least amount of ethanol was consumed in
conventional gasoline in the 7.2 billion gallon control case when a
maximum amount was allocated to RFG. Similarly, the most ethanol was
consumed in CG in the 9.6 billion gallon control case when a minimum
amount was allocated to RFG. For more information on the four resulting
2012 control cases, refer to DRIA Section 2.1.4.6.
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
consideration of the benefits of subsidies and credits provided by
Federal and state programs. Much of the demand occurred as a result of
mandates from states and local municipalities, which required the use
[[Page 55606]]
of biodiesel. However, over the past couple 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
corresponding rapid expansion in biodiesel production capacity.
Presently, there are 65 biodiesel plants in operation with an annual
production capacity of 395 million gallons per year.\55\ The majority
of the current production capacity was built in 2005, and was first
available to produce fuel in the last quarter of 2005. Though 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, see Table VI.B.1-2.\56\
---------------------------------------------------------------------------
\55\ NBB Survey April 28, 2006 ``Commercial Biodiesel Production
Plants.''
\56\ 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 Historya
----------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006
----------------------------------------------------------------------------------------------------------------
Plants....................................................... 9 11 16 22 45 53
Capacity (million gal/yr).................................... 50 54 85 157 290 354
----------------------------------------------------------------------------------------------------------------
\a\ Capacity Data based on surveys conducted around the month of September for most years, though the 2006
information is based on survey conducted in January 2006.
2. Expected Growth in U.S. Biodiesel Production/Consumption
In addition to the 53 biodiesel plants already in production, as of
early 2006, there were an additional 50 plants and 8 plant expansions
in the construction phase, which when completed would increase total
biodiesel production capacity to over one billion gallons per year.
Most of these plants should be completed by early 2007. There were also
36 more plants in various stages of the preconstruction phase (i.e.
raising equity, permitting, conceptual design, buying equipment) with a
capacity of 755 million gallons/year. As shown in Table VI.B.2-1, if
all of this capacity came to fruition, U.S. biodiesel capacity would
exceed 1.8 billion gallons.
Table VI.B.2-1.--Projected Biodiesel Production Capacity
----------------------------------------------------------------------------------------------------------------
Pre-
Existing Construction construction
plants phase phase
----------------------------------------------------------------------------------------------------------------
Number of plants............................................... 53 58 36
Total Plant Capacity, MM Gallon/year........................... 354 714 754.7
----------------------------------------------------------------------------------------------------------------
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 in a manner consistent with the growth of
gasoline.\57\ The resulting 2012 reference case consisted of
approximately 28 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.
---------------------------------------------------------------------------
\57\ 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
[[Page 55607]]
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. 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. Production Capacity of Cellulosic Ethanol
Beginning in 2013, a minimum of 250 million gallons per year of
cellulosic ethanol must be used in gasoline. The Act's definition of
cellulosic, however, includes corn based ethanol as long as greater
than 90% of the process energy was derived from animal wastes or other
waste materials. As discussed in section VI.A. above, we believe that
of the ethanol plants currently in existence, under construction, or in
the final stages of planning there is likely to be more than 250
million gallons per year of ethanol produced from plants which meet
these alternative definitions for cellulosic ethanol.
However, this is not to say that ethanol produced from cellulose
will not be part of the renewable supply by 2012. As far as we know
there is currently only one demonstration-level cellulosic ethanol
plant in operation in North America; it produces 1 million gallons of
ethanol per year (Iogen a privately held company, based in Ottawa,
Ontario, Canada). However, the technology used to produce ethanol from
cellulosic feedstocks continues to improve. With the grants made
available through the Energy Act, we expect several cellulosic process
plants will be constructed and an ever increasing effort will naturally
be made to find better, more efficient ways to produce cellulosic
ethanol.
To produce ethanol from cellulosic feedstocks, pretreatment is
necessary to hydrolyze cellulosic and hemicellulosic polymers and break
down the lignin sheath. In so doing, the structure of the cellulosic
feedstock is opened to allow efficient and effective enzyme hydrolysis
of the cellulose/hemicellulose to glucose and xylose. The central
problem is that the [alpha]-linked saccharide polymers in the
cellulose/hemicellulose structure prevent the microbial fermentation
reaction. By comparison, when corn kernels are used as feedstock,
fermentation of the starch produced from the corn kernels which have
[alpha]-linked saccharide polymers takes place much more readily. An
acid hydrolysis process was developed to pretreat cellulosic feedstocks
(through hydrolysis which breaks up the [beta]-links), but it continues
to be prohibitively expensive for producing ethanol.
Some technologies that are being developed may solve some of the
problems associated with production of ethanol from cellulosic sources.
Specifically, one problem with cellulosic feedstocks is that the
hydrolysis reactions produce both glucose, a six-carbon sugar, and
xylose, a 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 cellulose
hydrolysis enzymes and ethanol-fermenting organisms. Now, glucose and
xylose can be co-fermented--hence, the present-day terminology: Weak-
acid enzymatic hydrolysis and co-fermentation. In addition, several
research 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 a process known as weak-acid,
enzymatic-prehydrolysis.
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. In particular, there is only one cellulosic
ethanol plant in North America (Iogen, Ottawa, Ontario, Canada). To the
best of our knowledge, the technology that Iogen employs is not yet
fully developed or optimized. Generally, the industry seems to be
moving toward a process that uses dilute acid enzymatic prehydrolysis
with simultaneous saccharification (enzymatic) and co-fermentation.
3. Renewable Fuel Distribution System Capability
Ethanol and biodiesel blended fuels are 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 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. In the
past the refining industry has raised concerns regarding whether the
distribution infrastructure can expand rapidly enough to accommodate
the increased demand for ethanol. The most comprehensive study of the
infrastructure requirements for an expanded fuel ethanol industry was
conducted for the Department of Energy (DOE) in 2002.\58\ 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
[[Page 55608]]
contained in section VII.B. of this preamble.
---------------------------------------------------------------------------
\58\ ``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 and independent 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. We also expect that by
ending the use of MTBE that the former MTBE feedstock, isobutylene,
will be reused to produce increased volumes of alkylate, a moderate to
high octane gasoline blendstock. 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 production of
alkylate.
As discussed in section II., we chose to analyze a range of
renewable fuels 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, and the higher end is based on AEO 2006. 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
VII-1.
Table VII-1.--Renewable Fuels Volumes Used in Cost Analysis
------------------------------------------------------------------------
Renewable fuels consumption
in 2012 (billion gallons)
-------------------------------
Low High
------------------------------------------------------------------------
Corn Ethanol............................ 6.95 9.35
Cellulosic Ethanol...................... 0.25 0.25
Biodiesel............................... 0.30 0.30
-------------------------------
Total Biofuel Consumption........... 7.5 9.90
------------------------------------------------------------------------
We have estimated an average corn ethanol production cost of $1.20
per gallon in 2012 (2004 dollars) in the case of 7.5 billion gallons
per year (bill gal/yr) and $1.26 per gallon in the case of 9.9 bill
gal/yr. 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 this 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 gal in 2012. For yellow grease derived
biodiesel, we estimate an average production cost of $1.19 per gallon
in 2004 and $1.10 in 2012.
The impacts on overall gasoline costs with and without fuel
consumption subsidies resulting from the increased use of ethanol and
the corresponding changes to the other aspects of gasoline were
estimated for both of these cases. The 7.5 bill gal/yr case would
result in increased total costs which range from 0.33 cents to 0.41
cents per gallon depending on assumptions with respect to ethanol use
in RFG and butane control constraints. The 9.9 bill gal/yr case would
result in increased total costs which range from 0.93 to 1.05 cents per
gallon. The actual cost at the fuel pump, however, will be decreased
due the effect of State and Federal tax subsidies for ethanol. Taking
this into consideration results in ``at the pump'' decreased costs
(cost savings) ranging from 0.82 to 0.89 cents per gallon for the 7.5
bill gal/yr case and ``at the pump'' decreased costs ranging from 0.98
to 1.08 cents per gallon for the 9.9 bill gal/yr case. We ask for
comment on these derived costs as well as on the analysis methodology
used to derive these costs, and refer the reader to Section 7 of the
DRIA which contains much 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,\59\ and it produces results that
compare well with cost information found in surveys of existing
plants.\60\ 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.
---------------------------------------------------------------------------
\59\ Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B.,
Industrial Crops and Products 23 (2006) 288-296.
\60\ 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 represents about 50% of the final
per-gallon cost, while utilities, capital and labor comprise about 20%,
10%, and 5%, respectively. For this work, we used corn price
projections from USDA of $2.23 per bushel in 2012 for the 7.2 bill gal/
yr case, and an adjusted value of $2.31 per bushel for the 9.6 bill
gal/yr
[[Page 55609]]
case.\61\ The adjustment at the higher volume case was taken from work
done by FAPRI and EIA.62 63 Prices used for DDGS were $65
per ton in the 7.2 bill gal/yr case and $55 per ton in the 9.6 case,
based on work by FAPRI and EIA.\64\ Energy prices were derived from
historical data and projected to 2012 using EIA's AEO 2006.\65\ While
we believe the use of USDA and FAPRI estimates for corn and DDGS prices
is reasonable, additional modeling work is being done for the final
rulemaking using the Forestry and Agricultural Sector Optimization
Model described further in Chapter 8 of the RIA.
---------------------------------------------------------------------------
\61\ USDA Agricultural Baseline Projections to 2015, Report OCE-
2006-1.
\62\ EIA NEMS model for ethanol production, updated for AEO
2006.
\63\ Food and Agricultural Policy Research Institute (FAPRI)
study entitled ``Implications of Increased Ethanol Production for
U.S. Agriculture'', FAPRI-UMC Report 10-05.
\64\ Food and Agricultural Policy Research Institute (FAPRI)
U.S. and World Agricultural Outlook, January 2006, FAPRI Staff
Report 06-FSR 1.
\65\ Historical data at http://tonto.eia.doe.gov/dnav/pet/pet_pri_allmg_d_nus_PTA_cpgal_m.htm (gasoline), http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
(natural gas), http://www.eia.doe.gov/cneaf/electricity/page/sales_revenue.xls (electricity), http://www.eia.doe.gov/cneaf/coal/page/acr/table28.html (coal); EIA Annual Energy
Outlook 2006, Tables 8, 12, 13, 15; EIA Web site.
---------------------------------------------------------------------------
The estimated average corn ethanol production cost of $1.20 per
gallon in 2012 (2004 dollars) in the case of 7.2 bill gal/yr and $1.26
per gallon in the case of 9.6 bill gal/yr 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 does not account for any
subsidies on production or sale of ethanol. This cost is independent of
the market price of ethanol, which has been related closely to the
wholesale price of gasoline for the past decade.66 67
---------------------------------------------------------------------------
\66\ Whims, J., Sparks Companies, Inc. and Kansas State
University, ``Corn Based Ethanol Costs and Margins, Attachment 1''
(Published May 2002).
\67\ 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.\68\ It is expected that 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 these processes will simply be corn ethanol plants
with additional fuel handling mechanisms that allow them to combust
waste materials for process energy instead of natural gas. We expect
them to be in locations where the very low or zero cost of the waste
material or biogas itself will likely offset the costs of hauling it
and/or the additional capital for processing and firing it, making them
cost-competitive with conventional corn ethanol plants. Furthermore,
because the quantity of ethanol produced using these processes is still
expected to be a relatively small fraction of the total ethanol demand,
the sensitivity of the overall analysis to this assumption is also very
small. 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.
---------------------------------------------------------------------------
\68\ Energy Policy Act of 2005, Section 1501 amending Clean Air
Act Section 211(o)(1)(A).
---------------------------------------------------------------------------
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 hardwood
chips.\69\ 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.
---------------------------------------------------------------------------
\69\ 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 proposed 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.\70\ 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.
---------------------------------------------------------------------------
\70\ 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).
c. Ethanol's Blending Cost. Ethanol has a high octane value of 115
(R+M)/2 which contributes to its value as a gasoline blendstock. As the
volume of ethanol blended into gasoline increases from 2004 to 2012,
refiners will account for the octane provided by ethanol when they plan
their gasoline production. This additional octane would allow them to
back off of their octane production from their other gasoline producing
units resulting in a cost savings to the refinery. For this cost
analysis, the cost savings is expressed as a cost credit to ethanol
added to the production cost for producing ethanol.
We obtained gasoline blending costs on a PADD basis for octane from
a consultant who conducted a cost analysis for a renewable fuels
program using an LP refinery cost model. LP refinery models value the
cost of octane based on the octane producing capacity for the
refinery's existing units, by
[[Page 55610]]
added capital and operating costs for new octane producing capacity,
and based on purchased gasoline blendstocks. The value of octane is
expressed as a per-gallon cost per octane value, and ranges from 0.38
cents per octane-gallon in PADD 2 where lots of ethanol is expected to
be used, to 1.43 cents per octane-gallon in California. Octane is more
costly in California because the Phase 3 RFG standards restriction
aromatics content which also reduces the use of a gasoline blendstock
named reformate--a relatively cheap source of octane. Also,
California's Phase 3 RFG distillation restrictions tend to limit the
volume of eight carbon alkylate, another lower cost and moderately high
octane blendstock.
Another blending factor for ethanol is its energy content. Ethanol
contains a lower heat content per gallon than gasoline. Since refiners
blend up their gasoline based on volume, they do not consider the
energy content of its gasoline, only its price. Instead, the consumer
pays for a gasoline's energy density based on the distance that the
consumer can achieve on a gallon of gasoline. Since we try to capture
all the costs of using ethanol, we consider this effect. Ethanol
contains 76,000 British Thermal Units (BTU) per gallon which is
significantly lower than gasoline, which contains an average of 115,000
BTUs per gallon. This lower energy density is accounted for below in
the discussion of the gasoline costs.
2. Biodiesel Production Costs
We based our cost to produce biodiesel fuel on a range estimated
from the use of USDA's and NREL's biodiesel computer models. Both of
these models represent the continuous transesterification process for
converting vegetable soy oil to esters, along with the ester finishing
processes and glycerol recovery. The models estimate biodiesel
production costs using prices for soy oil, methanol, chemicals and the
byproduct glycerol. The models estimate the capital, fixed and
operating costs associated with the production of soy based biodiesel
fuel, considering utility, labor, land and any other process and
operating requirements.
Each model is based on a medium sized biodiesel plant that was
designed to process raw degummed virgin soy oil as the feedstock,
yielding 10 million gallons per year of biodiesel fuel. USDA estimated
the equipment needs and operating requirements for their biodiesel
plant 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. The NREL model is
also based on process simulation software, though the results are
adjusted to reflect NREL's modeling methods.
The production costs are based on an average biodiesel plant
located in the Midwest using soy oil 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 production costs are based on a
plant that makes 10 million gallons per year of biodiesel fuel.
The model is further modified to use input prices for the
feedstocks, byproducts and energy prices to reflect the effects of the
fuels provisions in the Energy Act. Based on the USDA model, for soy
oil-derived biodiesel we estimate a production cost of $2.06 per gallon
in 2004 and $1.89 per gal in 2012 (in 2004 dollars) For yellow grease
derived biodiesel, USDA's model estimates an average production cost of
$1.19 per gallon in 2004 and $1.10 in 2012 (in 2004 dollars). In order
to capture a range of production costs, we compared these cost
projections to those derived from the NREL biodiesel model. With the
NREL model, we estimate biodiesel production cost of $2.11 per gallon
for soy oil feedstocks and $1.28 per gallon for yellow grease in 2012,
which are slightly higher than the USDA results.
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 111 cents per
gallon for soy derived biodiesel and 60 to 78 cents per gallon for
yellow grease biodiesel 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
expires in 2008 if not extended. Congress may later elect to extend the
blender credit program, though, 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 under two scenarios, with refinery diesel prices
as forecasted by EIA's AEO 2006 with crude at $47 a barrel and with
refinery diesel prices based on $70 per barrel crude oil.
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 the AEO scenario, 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 $90 million per
year, which equates to a reduction in fuel cost of about 0.15 c/
gal.\71\ Without the subsidy, the transport diesel fuel costs are
increased by $118 million per year, or an increase of 0.20 c/gal for
transport diesel fuel. With crude at $70 per barrel, including the
biodiesel blenders subsidy, results in a cost reduction of $184 million
per
[[Page 55611]]
year, or a reduction of 0.31 c/gal for the total transport diesel pool.
Without the subsidy, transport diesel costs are increased by $25
million per year, or 0.04 c/gal.
---------------------------------------------------------------------------
\71\ Based on EIA's AEO 2006, the total volume of highway and
off-road diesel fuel consumed in 2012 was estimated at 58.9 billion
gallons.
---------------------------------------------------------------------------
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.\72\ That study
provided the foundation 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 the case where the minimum volume of ethanol is used to meet
the requirements of the RFS (7.2 bill gal/yr) and for the projected
case where the volume of ethanol used is 9.6 bill gal/yr. 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.
---------------------------------------------------------------------------
\72\ 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 bill gal/yr of ethanol
would be used in 2010, and the second assumed that 10 bill gal/yr of
ethanol would be used in the 2015 timetable. We interpolated between
these two cases to provide an estimate of the capital costs to support
the use of 7.2 bill gal/yr of ethanol in 2012.\73\ The 10 bill gal/yr
case examined in the DOE study was used to represent the projected case
examined in today's rule of 9.6 bill gal/yr of ethanol.\74\ Table
VII.B.1.a-1 contains 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, the total capital costs equate
to approximately one cent per gallon. We performed a sensitivity
analysis where we increased reliance on rail use at the expense of
barge use in transporting ethanol. The costs were relatively
insensitive, increasing to just 1.1 cents per gallon.
---------------------------------------------------------------------------
\73\ See Chapter 7.3 of the Draft 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.
\74\ For both the 7.2 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.
Table VII.B.1.a-1.--Estimated Ethanol Distribution Infrastructure
Capital Costs ($M) Relative to a 3.9 Billion Gallon per Year Reference
Case
------------------------------------------------------------------------
7.2 billion 9.6 billion
gallons (per gallons (per
year) year)
------------------------------------------------------------------------
Fixed Facilities:
Retail.............................. 24 44
Terminals........................... 142 246
Mobile Facilities:
Transport Trucks.................... 38 50
Barges.............................. 30 52
Rail Cars........................... 104 161
-------------------------------
Total Capital Costs............. 317 542
------------------------------------------------------------------------
b. Ethanol Freight Costs. The DOE study contains ethanol freight
costs for each of the 5 PADDs. The Energy Information Administration
translated these cost estimates to a census division basis.\75\ We took
the EIA projections and translated them into State-by-State ethanol
freight costs. In conducting this translation, we accounted for
increases in the cost in transportation fuels used to ship ethanol by
truck, rail, and barge. We estimate that the freight cost to transport
ethanol to terminals would range from 5 cents per gallon in the
Midwest, to 18 cents per gallon to the West Coast, which averages 9.2
cents per gallon of ethanol on a national basis.
---------------------------------------------------------------------------
\75\ 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.
---------------------------------------------------------------------------
We estimate the total cost for producing and distributing ethanol
to be between $1.30 and $1.36 per gallon of ethanol, on a nationwide
average basis. This estimate includes both the capital costs to upgrade
the distribution system and freight costs.
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 28 million gallons.\76\
---------------------------------------------------------------------------
\76\ 2004 baseline of 25 million gallons grown with diesel
demand to 2012.
---------------------------------------------------------------------------
For the purposes of this analysis, we are assuming that to ensure
consistent operations under cold conditions all terminals will install
heated biodiesel storage tanks and biodiesel will be transported to
terminals in insulated tank trucks and rail cars in the cold
seasons.\77\ Due to the developing nature of the biodiesel industry,
specific information on biodiesel freight costs is lacking. The need to
protect biodiesel from gelling during the winter may marginally
increase freight costs over those for ethanol. Counterbalancing this is
the likelihood that biodiesel shipping distances may be somewhat
shorter due to the more geographically dispersed nature of biodiesel
production facilities. In any event, the potential difference between
biodiesel and ethanol freight costs is likely to be small and the cost
of distributing biodiesel does not appreciably affect the results of
our analysis. Therefore, we believe that
[[Page 55612]]
estimated freight costs for ethanol of 9.2 cents per gallon adequately
reflects the freight costs for biodiesel for this analysis.
---------------------------------------------------------------------------
\77\ See section VI.C. in today's preamble regarding the special
handling requirements for biodiesel under cold conditions.
---------------------------------------------------------------------------
The capital costs associated with distribution of biodiesel will be
somewhat higher per gallon than those associated with the distribution
of ethanol due to the need for storage tanks, barges, tanker trucks and
rail cars to be insulated and in many cases heated. We estimate that to
handle the increased biodiesel volume will require a total capital cost
investment of $49,813,000, which equates to about 2 cents per gallon of
new biodiesel volume.
We estimate the total cost for producing and distributing biodiesel
to be between $2.00 and $2.22 per gallon of biodiesel, on a nationwide
average basis. This estimate includes both the capital costs to upgrade
the distribution system and freight costs.
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 developed our own spreadsheet cost model. As described above in
Section VI.A, the cost analysis is conducted by comparing a base year
before the Energy Act's fuel changes to a modeled year with the fuel
changes. We used 2004 as the base year. We grew the 2004 gasoline
demand to 2012 to create a reference case assuming that the 2004 fuel
demand scenario remained the same (fuel quality remained constant). The
sum of fuel changes, including the increased use of ethanol, the phase-
out of MTBE and the conversion of a part of the MTBE feedstocks to
alkylate, is all assumed to occur by 2012 and is compared to the 2012
reference case. This analysis considers the production cost,
distribution cost as well as the cost for balancing the octane and RVP
caused by these fuel changes.
In addition to assessing the cost at 7.2 and 9.6 billion gallons of
total ethanol use in gasoline, we considered that ethanol could be used
at different levels in RFG. Instead of picking a single point for
ethanol use in RFG, we assessed a range (see Section VI.A above). At
the high end of the range, ethanol is used in RFG in both summer and
winter. At the low end of the range, ethanol is still used in
wintertime RFG, but to only a very limited extent in summertime RFG.
The lower rate of ethanol use in summertime RFG may occur because the
RVP increase associated with ethanol will cause refiners to incur a
cost to further control the volatility of their summertime RFG.
1. RVP Cost for Blending Ethanol Into Summertime RFG
Blending ethanol into summertime RFG causes about a 1 PSI (pounds
per square inch) increase in RVP. To enable this gasoline to continue
to be sold into the summertime RFG market, this vapor pressure increase
must be accounted for by adjusting the RVP of the base gasoline. The
vapor pressure adjustment is made by reducing of volume of pentanes in
the gasoline boiling that comes from the fluid catalytic cracking unit
(FCCU). To reduce the pentane content FCC naphtha, refiners would
likely have to add a distillation column called a depentanizer, where
pentanes and lighter hydrocarbons are removed from the hydrocarbon feed
and drawn off the top of the column while the heavier C6+ hydrocarbons
are removed from the bottom. While the pentanes would be removed from
the summertime RFG pool, they are expected to be reblended into either
summertime CG or wintertime CG and RFG. To rebalance the RVP of the
nonsummertime RFG pool or wintertime RFG or CG pool caused by relocated
pentanes, butanes are estimated to be removed from the gasoline pool.
When ethanol is blended into summertime RFG, about 10 percent of the
base gasoline is lost due to the removed pentanes. We believe that
refiners would reblend these removed pentanes into summertime CG or
wintertime CG and RFG and rebalance the RVP of the gasoline pool into
which the pentanes are being reblended by removing butanes, thus
reducing the volume loss to one fifth of that if the pentanes were
permanently removed. There is an opportunity cost to removing butanes
from gasoline. In 2004 butanes sold into the butane market were valued
36 cents per gallon less than gasoline, however, this opportunity cost
would be much greater if pentanes were permanently removed from
gasoline.
We developed cost estimates for adding and operating a new
depentanizer distillation column for the removal of pentanes from FCC
naphtha in each refinery. The feed rate for an average FCC unit was
estimated by PADD and ranged from 7 to 35 thousand barrels per day.
Once the capital and operating costs were estimated, the total costs
were averaged over the entire gasoline pool, which ranged from about
two to three times the volume of FCC naphtha. When ethanol is being
blended newly into summertime RFG, the capital and operating costs will
both apply. However, when we model ethanol coming out of a summertime
RFG market, we only reduce the depentanizer operating costs since the
capital costs are sunk.
Our analysis showed that the RVP blending costs for blending
ethanol into summertime RFG ranges from 1 to 1.4 cents per gallon of
RFG. If the ethanol is coming out of summertime RFG, which occurs in
some of the scenarios that we modeled, there would be a cost savings of
0.8 to 1.2 cents per gallon of RFG.
In the cost of refinery gasoline section below, we took into
account that butanes have a lower energy density compared to the
gasoline pool from which the butanes were removed. This energy content
adjustment will offset some of the cost for removing the butanes.
Butane's energy density is 94,000 BTUs per gallon compared to 115,000
BTU per gallon for gasoline.
For further details on RVP reduction costs, see Section 7.4.2 of
the RIA.
2. Cost Savings for Phasing Out Methyl Tertiary Butyl Ether (MTBE)
The Energy Act rescinded the oxygen standard for RFG and when the
provision took effect, U.S. refiners stopped blending MTBE into
gasoline. When MTBE use ended, the operating costs for operating those
plants also ceased. The total costs saved for not operating the MTBE
plants is calculated by multiplying the volume of MTBE no longer
blended into gasoline with the operating costs for the plants producing
that MTBE.
We determined the operating costs saved by shutting down these
plants. The volumetric feedstock demands and the operating costs
factors for each of these MTBE plants are taken from literature. We
estimated the MTBE operating costs to be $1.40 per gallon for captive
and ethylene cracker plants, $1.48 per gallon for propylene oxide
plants and $1.55 per gallon for merchant operating costs. Weighted by
the percentages for domestic MTBE production, the average cost savings
for no longer producing MTBE is estimated to be $1.46 per gallon.
We also credited MTBE for its octane blending value. MTBE has a
high octane value of 110 (R+M)/2 which increases its value compared to
gasoline. This high octane value partially offsets its production cost.
The cost of octane is presented above in subsection VII.(A)(1)(c) and
is applied to the difference in octane value between MTBE and the
average of the various gasoline grades (88 (R+M)/2). Accounting for
MTBE's octane value reduces its cost down to $1.27 to $1.38 per gallon
depending on the PADD. When accounting for the volume of
[[Page 55613]]
MTBE removed, we also adjust for its energy content, which is 93,500
BTU per gallon.
For further information on costs savings due to MTBE phaseout, see
Section 7.4.3 of the RIA.
3. Production of Alkylate From MTBE Feedstocks
Discontinuing the blending of MTBE into U.S. gasoline is expected
to result in the reuse of most of the primary MTBE feedstocks,
isobutylene, to be used to produce alkylate. Alkylate is formed by
reacting isobutylene together with isobutane. Prior to the
establishment of the oxygen requirement for RFG, this isobutylene was,
in most cases, used to make alkylate. Another option would be for
reacting isobutylene with itself to form isooctene which would likely
be hydrogenated to then form isooctane. However, our cost analysis
found that alkylate is a more cost-effective way to reuse the
isobutylene, even after considering isooctane's higher octane content.
The cost for converting to alkylate is estimated to be $1.42 per gallon
for captive (in-refinery) plants and ethylene cracker plants, $1.46 per
gallon for propylene oxide plants and $1.52 per gallon for merchant
MTBE plants. We believe that the cost for converting merchant MTBE
plants to alkylate is too high to support its conversion, thus the
conversion cost is estimated to be $1.43 per gallon, the average of the
conversion costs for captive, ethylene cracker and propylene oxide MTBE
plants. This projected percent of MTBE plant conversion results in 0.84
gallons of alkylate produced for each gallon of MTBE no longer
produced.
The alkylate production cost is adjusted by PADD to account for the
blending octane of alkylate, which varies by 1 to 2 cents per gallon
depending on the value of octane in each PADD. Including its octane
value, the cost of producing alkylate varies from $1.38 to $ 1.41 per
gallon.
For further information on production of alkylate from MTBE
feedstocks, see section 7.4.4 of the RIA.
4. Changes in Refinery Produced Gasoline Volume and Its Costs
In the sections above, we estimated changes in gasoline volume and
the cost associated with those volume changes for ethanol, MTBE,
alkylate and butane. As these various gasoline blendstocks are added to
or removed from the gasoline pool, they affect the refinery production
of gasoline (or oxygenate blendstock).
To estimate the changes in refinery gasoline production volumes, it
was necessary to balance the total energy production of each control
case to the reference case. The energy content of the reference case
was estimated by multiplying the volumetric energy content of each
gasoline pool blendstock, including MTBE, ethanol and refinery produced
gasoline, by the associated gallons.
The increase or decrease in ethanol content in summertime RFG
assumed under the different scenarios resulted in the change in the
volumes of butane in RFG as described above. We identified that the
increase or decrease in ethanol in wintertime RFG and CG could cause
reductions or increases in the amount of butanes blended into
wintertime gasoline. Wintertime gasoline is limited in vapor pressure
by the American Standard for Testing Materials (ASTM) RVP and V/L
(vapor-liquid) standards. According to a refiner with extensive
refining capacity, and also Jacobs Engineering, a refining industry
consulting firm, refineries are blending their wintertime gasoline up
to those standards today and are limited from blending more butane
available to them. If this is the case, for each gallon of summertime
RFG and wintertime RFG and CG blended with ethanol 2 percent of the
base gasoline volume would be lost in terms of butane removed. However,
some refineries may have room to blend more butane. Also, we are aware
that some states offer 1 PSI waivers for blending of ethanol into
wintertime gasoline, presumably to accommodate splash blending of
ethanol.\78\ Consequently, it may be possible to accommodate the 1 PSI
vapor pressure increase without forcing the removal of some or all of
this butane. For this reason we assessed the costs as a range, on the
upper end assuming that butane content would have to be removed to
account for new ethanol blended into summertime RFG and wintertime RFG
and CG , and on the low end assuming only that blending of ethanol into
summertime RFG cause butanes to be removed.
---------------------------------------------------------------------------
\78\ Most people are aware of the 1 PSI RVP waiver that ethanol
is provided for the summertime, but some states offer a similar
waiver to ethanol for wintertime blending as well.
---------------------------------------------------------------------------
For estimating the volume of butane which must be removed from the
gasoline because of the addition of ethanol, we assumed that ethanol
will be used at 10 volume percent except for California where it would
continue to be used at 5.7 volume percent. Development of the estimates
for winter vs. summer ethanol consumption for the control cases is
discussed in Chapter 2.1 of the RIA. For the reference case, we
estimated that 55 percent of the ethanol would be used in the winter
and 45 percent in the summer. Table VII.C.4-1 summarizes the summertime
RFG and wintertime RFG and CG volumes of ethanol and estimated change
in butane content.
Table VII.C.4-1.--Estimated Changes in U.S. Summertime RFG Ethanol Volumes and Their Impact on Butane Blending Into Gasoline
[Million gallons in 2012]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Reference case 7.2 Bil gals max RFG 7.2 Bil gals min RFG 9.6 Bil gals max RFG 9.6 Bil gals min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Summertime RFG Ethanol............. 1,155................. 1,932................. 244.................. 1,932................ 244
Wintertime RFG & CG Ethanol........ 2,178................. 3,999................. 4,812................ 5,303................ 6,132
Change in Butane................... ...................... -140 to -456.......... 164 to -297.......... -140 to -690......... 164 to -535
--------------------------------------------------------------------------------------------------------------------------------------------------------
The change in volume of ethanol, MTBE, alkylate, and butane for
each control case is adjusted for energy content. The volume of
refinery gasoline is then adjusted to maintain the same energy content
as that of the reference gasoline pool. The refinery gasoline
production is estimated by dividing the BTU content of gasoline,
estimated to be 115,000 BTU per gallon, into the total amount of BTUs
for the entire gasoline pool after accounting for the BTUs of the other
blendstocks. The BTU-balanced gasoline pool volumes for each control
case are shown in Table
[[Page 55614]]
VII.C.4-2. The changes are shown for both assumptions with respect to
the need to remove butane from winter gasoline to accommodate more
ethanol blending.
Table VII.C.4-2.--Estimated 2012 Volumes
[Million gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
7.2 Bil gals, max RFG
7.2 Bil gals, min RFG
9.6 Bil gals, max RFG
9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Ethanol........................................... 7,200
7,200
9,600
9,600
Increase in Ethanol..................................... 3,302
3,302
5,702
5,702
Change in MTBE.......................................... -2091
-2091
-2091
-2091
New Alkylate............................................ 1,763
1,764
1,764
1,764
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................ Yes No Yes No Yes No Yes No
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Butane........................................ -456 -140 -297 164 -690 -140 -535 164
Gasoline................................................ 143,486 143,228 143,357 142,980 142,092 141,642 141,965 141,394
Change in Gasoline...................................... -1,873 -2,131 -2,002 -2,379 -3,267 -3,716 -3,394 -3,965
Change in Gasoline (%).................................. -1.3 -1.5 -1.4 -1.6 -2.2 -2.6 -2.3 -2.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Based on our estimated impacts on volumes shown in table VII.C.4-2,
refinery produced gasoline demand will be reduced by a range of 1.3
percent to 2.7 percent compared to the reference case, which would
result in less imported finished petroleum products and/or less crude
oil use. The projected impacts on refinery-produced gasoline demand
depend on the volume of new ethanol blended into gasoline, on the
volume of ethanol blended into summertime RFG and on whether butane
blending into wintertime gasoline will be affected or not. To put this
reduction in refinery-produced gasoline volume in perspective, the
yearly annual growth in gasoline demand in this country is about 1.7
percent.
The cost for changes to refinery produced gasoline volume is
assumed to be represented by the bulk price of gasoline in each PADD
from EIA's 2004 Petroleum Marketing Annual. The 2004 gasoline cost is
adjusted to 2012 using the ratio of the projected crude oil price in
2012 of $47 per barrel to that in the 2004 base case of $41 per barrel.
The cost for distributing the gasoline to terminals is added on, which
is estimated to be 4 cents per gallon. The estimated cost for producing
and distributing gasoline to terminals (wholesale price at the terminal
rack) ranges from $1.30 per gallon in the Gulf Coast, to $1.53 per
gallon in California.
Crude oil prices are much higher today which decreases the relative
cost of producing and blending in more ethanol into gasoline. For this
reason, we conducted a sensitivity analysis assuming that crude oil is
priced at around $70 per barrel. Since this is only a sensitivity
analysis, we simply ratioed the gasoline production costs, MTBE and
alkylate feedstock costs and butane value upwards by the same ratio.
The ratio is determined by the projected increase in the wholesale
gasoline price relative to the increase in crude oil price. We
extrapolated this relationship to crude oil priced at $70 per barrel
compared to the price in 2004 which was $41 per barrel, which results
in about a 1.4 ratio factor. We did not adjust other costs and
assumptions which are much less sensitive to the price of crude oil and
therefore not likely to change much (e.g., distribution costs, refinery
utility costs, incremental octane costs, and ethanol production costs).
At a $70 per barrel crude oil price, the cost for production and
distribution of gasoline to the terminal ranges from $2.05 in the Gulf
Coast to $2.43 per gallon in California.
For further information on gasoline cost see section 7.4.5 in the
RIA.
5. Overall Impact on Fuel Cost
We combined the costs and volume impacts described in the previous
sections to estimate an overall fuel cost impact due to the changes in
gasoline occurring with the projected fuel changes. This aggregated
cost estimate includes the costs for producing and distributing
ethanol, the blending costs of ethanol in summertime RFG, ending the
production and distribution of MTBE, and reusing the MTBE feedstock
isobutylene for producing alkylate, reducing the content of butane in
summertime RFG and wintertime gasoline and for reducing the volume of
refinery-produced gasoline. We also present the costs for the scenario
that butanes would not need to be removed when ethanol is blended into
wintertime gasoline. The costs for each control case are estimated by
multiplying the change in volume for each gasoline blendstock, relative
to the reference case, times its production, distribution and octane
blending costs.
The costs of these fuels changes 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. The second way we
express the cost is with the ethanol consumption subsidies included
since the subsidized portion of the renewable fuels costs will be 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. For
both cases we express the costs with and without butanes being removed
due to changes in wintertime blending of ethanol. We evaluated the fuel
costs using ranges in different assumptions to bound the many
uncertainties in the cost analysis (see the DRIA for more discussion
concerning the cost uncertainties).
a. Cost without Ethanol Subsidies. Table VII.C.5.a-1 summarizes the
costs without ethanol subsidies for each of the four control cases,
including the cost for each aspect of the fuels changes, and the
aggregated total and the per-gallon costs for all the fuel changes.\79\
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. We excluded Federal and state ethanol consumption
subsidies
[[Page 55615]]
which avoids the transfer payments caused by these subsidies that would
hide a portion of the program's costs.
---------------------------------------------------------------------------
\79\ 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.
Table VII.C.5.a-1.--Estimated Cost Without Ethanol Consumption Subsidies ($47/bbl Crude)
[million dollars, except where noted]
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
7.2 Bil gals, max RFG
7.2 Bil gals, min RFG
9.6 Bil gals, max RFG
9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Adding Ethanol.......................................... 3,769
3,837
6,852
6,897
RFG RVP Cost............................................ 72
-74
72
-74
Eliminating MTBE........................................ -2,821
-2,821
-2,821
-2,821
Adding Alkylate......................................... 2,520
2,520
2,521
2,521
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................ Yes No Yes No Yes No Yes No
--------------------------------------------------------------------------------------------------------------------------------------------------------
Changing Butane Volume.................................. -439 -133 -275 174 -667 -133 -510 174
Additional Gasoline Production.......................... -2,484 -2,826 -2,638 -3,141 -4,350 -4,948 -4,507 -5,270
Total Cost Excluding Subsidies.......................... 619 582 548 496 1,606 1,542 1,507 1,426
Per-Gallon Cost Excluding Subsidies (cents per gallon).. 0.41 0.38 0.38 0.33 1.05 1.01 0.99 0.93
--------------------------------------------------------------------------------------------------------------------------------------------------------
Our analysis shows that when considering all the costs associated
with these fuel changes resulting from the expanded use of subsidized
ethanol that these various possible gasoline use scenarios will cost
the U.S. $0.5 billion to around $1.6 billion in the year 2012.
Expressed as per-gallon costs, these fuel changes would cost the U.S.
0.3 to just over 1 cent per gallon of gasoline.
b. Gasoline Costs Including Ethanol Consumption Tax Subsidies.
Table VII.C.5.b-1 expresses the total and per-gallon gasoline costs for
the four control scenarios with the Federal and state ethanol subsidies
included. The Federal tax subsidy is 51 cents per gallon for each
gallon of new ethanol blended into gasoline. The state tax subsidies
apply in 5 states and range from 1.6 to 29 cents per gallon. The cost
reduction to the fuel industry and consumers are estimated by
multiplying the subsidy times the volume of new ethanol estimated to be
used in the state. The costs are presented for the case that ethanol
causes butanes to be withheld from the wintertime gasoline pool, and
for the case that the blending of butanes remains unchanged.
Table VII.C.5.b-1.--Estimated Cost Including Subsidies ($47/bbl Crude)
[million dollars, except where noted]
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
7.2 Bil Gals Max RFG
7.2 Bil Gals Min RFG
9.6 Bil Gals Max RFG
9.6 Bil Gals Min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................ Yes No Yes No Yes No Yes No
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Cost without Subsidies............................ 619 582 548 496 1,606 1,542 1,507 1,426
Federal Subsidy......................................... -1,684 -1,684 -1,684 -1,684 -2,908 -2,908 -2,908 -3,908
State Subsidies......................................... -180 -180 -173 -173 -189 -189 -176 -176
Total Cost Including Subsidies.......................... -1,245 -1,282 -1,308 -1,361 -1,491 -1,555 -1,578 -1,657
Per-Gallon Cost Including Subsidies (cents/gallon)...... -0.82 -0.84 -0.86 -0.89 -0.98 -1.02 -1.03 -1.08
--------------------------------------------------------------------------------------------------------------------------------------------------------
The cost including subsidies better represents gasoline's
production cost as might be reflected to the fuel industry as a whole
and to consumers ``at the pump'' because the Federal and state
subsidies tends to hide a portion of the actual costs. Our analysis
suggests that the fuel industry and consumers will see a 0.8 to 1.1
cent per gallon decrease in the apparent cost of producing gasoline
with these changes to gasoline.
c. Cost Sensitivity Case Assuming $70 per Barrel Crude Oil. As
described above, we analyzed a sensitivity analysis with the future
price of crude oil remained at today's prices which is around $70 per
barrel. This analysis was conducted by applying about a 1.4
multiplication factor times the 2004 gasoline production costs, MTBE
and alkylate feedstock costs and butane value. This factor was derived
by examining the historical association between increasing wholesale
gasoline prices with increasing crude oil prices. We did not adjust the
distribution costs, any of the utility costs, octane value and ethanol
prices based on the assumption that these would change much less and
therefore we kept them the same as that used in the primary analysis.
The cost results of the sensitivity analysis are provided with and
without the ethanol consumption subsidies in Table VII.C.5.c-1.
Table VII.C.5.c-1.--Estimated Costs for Crude Oil Priced at $70 Per Barrel
[Million dollars and cents per gallon]
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
7.2 Bil gals, max RFG
7.2 Bil gals, min RFG
9.6 Bil gals, max RFG
9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................ Yes No Yes No Yes No Yes No
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 55616]]
Total Cost without Subsidies ($million)................. -171 -187 -223 -245 222 196 138 105
Per-Gallon Cost without Subsidies (c/gal)............... -0.11 -0.12 -0.15 -0.16 0.15 0.13 0.09 0.07
Total Cost Including Subsidies ($million)............... -2,035 -2,051 -2,080 -2,102 -2,875 -2,901 -2,945 -2,978
Per-Gallon Cost Including Subsidies (c/gal)............. -1.34 -1.35 -1.37 -1.38 -1.88 -1.90 -1.93 -1.95
--------------------------------------------------------------------------------------------------------------------------------------------------------
If crude oil stays priced at around $70 per barrel, the cost of
these fuel changes would decrease significantly. In fact, we estimate
that the 7.2 billion gallon ethanol case would result in a cost savings
to the U.S. even if butanes are removed from the wintertime gasoline
pool when ethanol is added. When considering the ethanol subsidies, the
incentive to blend in ethanol becomes much stronger at today's crude
oil prices likely causing a rapid increase in ethanol production
volume.
VIII. What Are the Impacts of Increased Ethanol Use on Emissions and
Air Quality?
In this section, we evaluate the impact of increased production and
use of renewable fuels on emissions and air quality in the U.S.,
particularly ethanol and biodiesel. In performing these analyses, we
compare the emissions which would have occurred in the future if fuel
quality had remained unchanged from pre-Act levels to those which will
be required under the Energy Policy Act of 2005 (Energy Act or the
Act). This approach differs from that traditionally taken in EPA
regulatory impact analyses. Traditionally, we would have compared
future emissions with and without the requirement of the Energy Act.
However, as described in Section VI, we expect that total renewable
fuel use in the U.S. in 2012 to exceed 7.5 billion gallons even in the
absence of the RFS program. Thus, a traditional regulatory impact
analysis would have shown no impact on emissions or air quality.
Strictly speaking, if the same volume and types of renewable fuels
are produced and used with and without the RFS program, the RFS program
is having no impact on emissions or air quality. However, levels of
renewable fuel use are increasing dramatically relative to both today
and the recent past, with corresponding impacts on emissions and air
quality. We believe that it is appropriate to evaluate these changes
here, regardless of whether they are occurring due to economic forces
or Energy Act requirements.
In the process of estimating the impact of increased renewable fuel
use, we also include the impact of reduced use of MTBE in gasoline. It
is the increased production and use of ethanol which is facilitating
the removal of MTBE while still producing the required volume of RFG
which meets both commercial and EPA regulatory specifications. Because
of this connection, we found it impractical to isolate the impact of
increased ethanol use from the removal of MTBE.
A. Effect of Renewable Fuel Use on Emissions
1. Emissions From Gasoline Fueled Motor Vehicles and Equipment
Several models of the impact of gasoline quality on motor vehicle
emissions have been developed since the early 1990's. We evaluated
these models and selected those which were based on the most
comprehensive set of emissions data and developed using the most
advanced statistical tools for this analysis. Still, as will be
described below, significant uncertainty still exists as to the effect
of these gasoline components on emissions from both motor vehicle and
nonroad equipment, particularly from the latest models equipped with
the most advanced emission controls. Pending adequate funding, we plan
to conduct significant vehicle and equipment testing over the next
several years to improve our estimates of the impact of these additives
and other gasoline properties on emissions. The results of this testing
will not be available for inclusion in the analyses supporting this
rulemaking. We hope that the results from these test programs will be
available for reference in the future evaluations of the emission and
air quality impacts of U.S. fuel programs required by the Act.\80\
---------------------------------------------------------------------------
\80\ Subject to funding.
---------------------------------------------------------------------------
The remainder of this sub-section is divided into three parts. The
first evaluates the impact of increased ethanol use and decreased MTBE
use on gasoline quality. The second evaluates the impact of increased
ethanol use and decreased MTBE use on motor vehicle emissions. The
third evaluates the impact of increased ethanol use and decreased MTBE
use on nonroad equipment emissions.
a. Gasoline Fuel Quality. For this proposal, we estimate the impact
of ethanol use on gasoline quality using fuel survey data obtained by
Alliance of Automobile Manufacturers (AAM) from 2001-2005.\81\ We
estimate the impact of removing MTBE from gasoline based on refinery
modeling performed in support of the RFG rulemaking. We plan to update
these estimates for the FRM using refinery modeling which is currently
underway. In general, as shown in Table VIII.A.1.a-1, adding ethanol to
gasoline is expected to reduce levels of aromatics and olefins in
conventional gasoline, as well as reduce mid and high distillation
temperatures (e.g., T50 and T90). RVP is expected to increase, as most
areas of the country grant ethanol blends a 1.0 RVP waiver of the
applicable RVP standards in the summer. With the exception of RVP, the
effect of removing MTBE results in essentially the opposite impacts.
Please see Chapter 2 of the DRIA for a detailed description of the
methodologies used and the specific changes in projected fuel quality.
---------------------------------------------------------------------------
\81\ Alliance of Automobile Manufacturers North American Fuel
Survey 2005. For the final rule, we intend to supplement this
empirical approach with the results of refinery modeling which might
better capture all of the effects of ethanol blending on gasoline
quality.
[[Page 55617]]
Table VIII.A.1.a-1.--CG Fuel Quality With and Without Oxygenates
------------------------------------------------------------------------
Typical 9 MTBE CG Ethanol CG
Fuel parameter RVP CG blend blend
------------------------------------------------------------------------
RVP (psi)........................... 8.7 8.7 9.7
T50................................. 218 206 186
T90................................. 332 324 325
Aromatics (vol%).................... 32 25.5 27
Olefins (vol%)...................... 7.7 7.7 6.1
Oxygen (wt%)........................ 0 2 3.5
Sulfur (ppm)........................ 30 30 30
Benzene (vol%)...................... 1.0 1.0 1.0
------------------------------------------------------------------------
The effect of adding ethanol and removing MTBE on the quality of
RFG is expected to very limited. RFG must meet stringent VOC,
NOX and toxics performance standards. Thus, the natural
effects of MTBE and ethanol blending on gasoline must often be
addressed through further refining. The largest differences are
expected to exist in terms of the distillation temperatures, due to the
relatively low boiling point of ethanol. Other fuel parameters are
expected to be very similar. For this analysis we have assumed no
changes to fuel parameters other than ethanol and MTBE content for RFG.
b. Emissions from Motor Vehicles. We use the EPA Predictive Models
to estimate the impact of gasoline fuel quality on exhaust VOC and
NOX emissions from motor vehicles. These models were
developed in 2000, in support of EPA's response to California's request
for a waiver of the RFG oxygen mandate. These models represent a
significant update of the EPA Complex Model. However, they are still
based on emission data from Tier 0 vehicles (roughly equivalent to 1990
model year vehicles). We based our estimates of the impact of fuel
quality on CO emissions on the EPA MOBILE6.2 model. We base our
estimates of the impact of fuel quality on exhaust toxic emissions
(benzene, formaldehyde, acetaldehyde, and 1,3-butadiene) primarily on
the MOBILE6.2 model, updated to reflect the effect of fuel quality on
exhaust VOC emissions per the EPA Predictive Models. Very limited data
are available on the effect of gasoline quality on PM emissions.
Therefore, the effect of increased ethanol use on PM emissions can only
be qualitatively discussed.
In responding to California's request for a waiver of the RFG
oxygen mandate in 2000, we found that both very limited and conflicting
data were available on the effect of fuel quality on exhaust emissions
from Tier 1 and later vehicles.\82\ Thus, we assumed at the time that
changes to gasoline quality would not affect VOC, CO and NOX
exhaust emissions from these vehicles. Very little additional data has
been collected since that time on which to modify this assumption.
Consequently, for our primary analysis for today's proposal we have
maintained the assumption that changes to gasoline do not affect
exhaust emissions from Tier 1 and later technology vehicles.
---------------------------------------------------------------------------
\82\ The one exception was the impact of sulfur on emissions
from these later vehicles, which is not an issue here due to the
fact that renewable fuel use is not expected to change sulfur levels
significantly.
---------------------------------------------------------------------------
There is one recent study by the Coordinating Research Council
(CRC) which assessed the impact of ethanol and two other fuel
properties on emissions from twelve 2000-2004 model year vehicles (CRC
study E-67). The results of this program indicate that emissions from
these late model year vehicles may be at least as sensitive to changes
to these three fuel properties as Tier 0 vehicles on a percentage
basis.\83\ However, because this study is the first of its kind and not
all relevant fuel properties have yet been studied, in our primary
analysis we continue to assume that exhaust emissions from Tier 1 and
later vehicles are not sensitive to fuel quality. Based on the
indications of the CRC E-67 study, we also conducted a sensitivity
analysis where the exhaust VOC and NOX emission impacts for
all vehicles were assumed to be as sensitive to fuel quality as Tier 0
vehicles (i.e., as indicated by the EPA Predictive Models).
---------------------------------------------------------------------------
\83\ The VOC and NOX emissions from the 2000-2004
model year vehicles are an order of magnitude lower than those from
the Tier 0 vehicles used to develop the EPA Complex and Predictive
Models. Thus, a similar impact of a fuel parameter in terms of
percentage means a much smaller impact in terms of absolute
emissions.
---------------------------------------------------------------------------
We base our estimates of fuel quality on non-exhaust VOC and
benzene emissions on the EPA MOBILE6.2 model. The one exception to this
is the effect of ethanol on permeation emissions through plastic fuel
tanks and elastomers used in fuel line connections. Recent testing has
shown that ethanol increases permeation emissions, both by permeating
itself and increasing the permeation of other gasoline components. This
effect was included in EPA's analysis of California's most recent
request for a waiver of the RFG oxygen requirement, but is not in
MOBILE6.2.\84\ Therefore, we have added the effect of ethanol on
permeation emissions to MOBILE6.2's estimate of non-exhaust VOC
emissions in assessing the impact of gasoline quality on these
emissions.
---------------------------------------------------------------------------
\84\ For more information on California's request for a waiver
of the RFG oxygen mandate and the Decision Document for EPA's
response, see http://www.epa.gov/otaq/rfg_regs.htm#waiver.
---------------------------------------------------------------------------
No models are available which address the impact of gasoline
quality on PM emissions. Very limited data indicate that ethanol
blending might reduce exhaust PM emissions under very cold weather
conditions (e.g., -20 F to 0 F). Very limited testing at warmer
temperatures (e.g., 20 F to 75 F) shows no definite trend in PM
emissions with oxygen content. Thus, for now, no quantitative estimates
can be made regarding the effect of ethanol use on direct PM emissions.
Table VIII.A.1.b-1 presents the average per vehicle (2012 fleet)
emission impacts of three types of RFG: Non-oxygenated, a typical MTBE
RFG as has been marketed in the Gulf Coast, and a typical ethanol RFG
which has been marketed in the Midwest.
[[Page 55618]]
Table VIII.A.1.b-1.--Effect of RFG on Per Mile Emissions From Tier 0 Vehicles Relative to a Typical 9psi RVP
Conventional Gasoline a
----------------------------------------------------------------------------------------------------------------
10 Volume
Pollutant Source Non-Oxy RFG 11 Volume percent
(percent) percent MTBE ethanol
----------------------------------------------------------------------------------------------------------------
Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC................................... EPA Predictive Models... -7.7 -11.1 -12.9
NOX................................... ........................ -1.7 2.4 6.3
CO.................................... MOBILE6.2............... -24 -28 -32
Exhaust Benzene....................... EPA Predictive and -18 -30 -35
Complex Models.
Formaldehyde.......................... ........................ 7 11 2
Acetaldehyde.......................... ........................ 7 -8 143
1,3-Butadiene......................... ........................ 22 2 -7
----------------------------------------------------------------------------------------------------------------
Non-Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC................................... MOBILE6.2 & CRC E-65.... -30 -30 -18
Benzene............................... MOBILE6.2 & Complex -5 -15 -7
Models.
----------------------------------------------------------------------------------------------------------------
\a\ Average per vehicle effects for the 2012 fleet during summer conditions.
As can be seen, the oxygenated RFG blends are predicted to produce
a greater reduction in exhaust VOC and CO emissions than 9 RVP
conventional gasoline, but a larger increase in NOX
emissions. This comparison assumes that all gasoline meets EPA's Tier 2
gasoline sulfur standard of 30 ppm. Prior to this program, RFG
contained less sulfur than conventional gasoline and produced less
NOX emissions. Non-exhaust VOC emissions with the exception
of permeation are roughly the same due to the fact that the RVP level
of the three blends is the same. However, the increased permeation
emissions associated with ethanol reduces the overall effectiveness of
ethanol RFG.
An increase in ethanol use will also impact emissions of air
toxics. We evaluated effects on four air toxics affected by fuel
parameter changes in the Complex Model-benzene, formaldehyde,
acetaldehyde and 1,3-butadiene. The most notable effect on toxic
emissions in percentage terms is the increase in acetaldehyde with the
use of ethanol. Acetaldehyde emissions more than double. However, as
will be seen below, base acetaldehyde emissions are low relative to the
other toxics. Thus, the absolute increase in total emissions of these
four air toxics is still relatively low.
Table VIII.A.1.b-2 presents the effect of blending either MTBE or
ethanol into conventional gasoline while matching octane.
Table VIII.A.1.b-2.--Effect of MTBE and Ethanol in Conventional Gasoline on Tier 0 Vehicle Emissions Relative to
a Typical Non-Oxygenated Conventional Gasoline a
----------------------------------------------------------------------------------------------------------------
10 Volume
Pollutant Source 11 Volume percent
percent MTBE ethanol \b\
----------------------------------------------------------------------------------------------------------------
Exhaust VOC..................................... EPA Predictive Models............. -9.2 -7.4
NOX............................................. .................................. 2.6 7.7
CO \c\.......................................... MOBILE6.2......................... -6/-11 -11/-19
Exhaust Benzene................................. EPA Predictive and Complex Models. -22 -27
Formaldehyde.................................... .................................. +10 +3
Acetaldehyde.................................... .................................. -8 +141
1,3-Butadiene................................... .................................. -12 -27
Non-Exhaust VOC................................. MOBILE6.2......................... 0 +17
Non-Exhaust Benzene............................. MOBILE6.2 & Complex Models........ -10 +13
----------------------------------------------------------------------------------------------------------------
\a\ Average per vehicle effects for the 2012 fleet during summer conditions.
\b\ Assumes a 1.0 psi RVP waiver for ethanol blends.
\c\ The first figure shown applies to normal emitters; the second applies to high emitters.
As was the case with the RFG blends, the two oxygenated blends both
reduce exhaust VOC and CO emissions, but increase NOX
emissions. The MTBE blend does not increase non-exhaust VOC emissions,
but the ethanol blend does due to the commonly granted waiver of the
RVP standard. Both blends have lower exhaust benzene and 1,3-butadiene
emissions. As above, ethanol increases non-exhaust benzene and
acetaldehyde emissions.
The exhaust emission effects shown above for VOC and NOX
emissions only apply to Tier 0 vehicles in our primary analysis. For
example, MOBILE6.2 estimates that 34% of exhaust VOC emissions and 16%
of NOX emissions from gasoline vehicles in 2012 come from
Tier 0 vehicles. In the sensitivity analysis, these effects are
extended to all gasoline vehicles. The effect of RVP on non-exhaust VOC
emissions is temperature dependent. The figures shown above are based
on the distribution of temperatures occurring across the U.S. in July.
c. Nonroad Equipment. To estimate the effect of gasoline quality on
emissions from nonroad equipment, we used EPA's NONROAD emission model.
We used the 2005 version of this model, NONROAD2005, which includes the
effect of ethanol on permeation emissions from most nonroad equipment.
[[Page 55619]]
Only sulfur and oxygen content affect exhaust VOC, CO and
NOX emissions in NONROAD. Since sulfur level is assumed to
remain constant, the only difference in exhaust emissions between
conventional and reformulated gasoline is due to oxygen content. Table
VIII.A.1.c-1 shows the effect of adding 11 volume percent MTBE or 10
volume percent ethanol to non-oxygenated gasoline on these emissions.
Table VIII.A.1.c-1.--Effect MTBE and Ethanol on Nonroad Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
4-Stroke engines 2-Stroke engines
---------------------------------------------------
Base fuel 11 Volume 10 Volume 11 Volume 10 Volume
percent percent percent percent
MTBE ethanol MTBE ethanol
----------------------------------------------------------------------------------------------------------------
Exhaust VOC................................................. -9 -15 -1 -1
Non-Exhaust VOC 0........................................... 0 26 0 26
CO.......................................................... -13 -21 -8 -12
NOX......................................................... +24 +37 +12 +18
----------------------------------------------------------------------------------------------------------------
As can be seen, higher oxygen content reduces exhaust VOC and CO
emissions significantly, but also increases NOX emissions.
However, NOX emissions from these engines tend to be fairly
low to start with, given the fact that these engines run much richer
than stoichiometric. Thus, a large percentage increase of a relative
low base value can be a relatively small increase in absolute terms.
Evaporative emissions from nonroad equipment are impacted by only
RVP, and permeation by ethanol content. Both the RVP increase due to
blending of ethanol and its permeation effect cause non-exhaust VOC
emissions to increase with the use of ethanol in nonroad equipment. The
26 percent effect represents the average impact across the U.S. in July
for both 2-stroke and 4-stroke equipment. We updated the NONROAD2005
hose permeation emission factors for small spark-ignition engines and
recreational marine watercraft to reflect the use of ethanol.
For nonroad toxics emissions, we base our estimates of the impact
of fuel quality on the fraction of exhaust VOC emissions represented by
each toxic on MOBILE6.2 (i.e., the same effects predicted for onroad
vehicles). The National Mobile Inventory Model (NMIM) contains
estimates of the fraction of VOC emissions represented by the various
air toxics based on oxygenate type (none, MTBE or ethanol). However,
estimates for nonroad gasoline engines running on different fuel types
are limited, making it difficult to accurately model the impacts of
changes in fuel quality. In the recent NPRM addressing mobile air toxic
emissions, EPA replaced the toxic-related fuel effects contained in
NMIM with those from MOBILE6.2 for onroad vehicles.\85\ We follow the
same methodology here. Future testing could significantly alter these
emission impact estimates.
---------------------------------------------------------------------------
\85\ 71, Federal Register, 15804, March 29, 2006.
---------------------------------------------------------------------------
2. Diesel Fuel Quality: Biodiesel
EPA assessed the impact of biodiesel fuel on emissions in 2002 and
published a draft report summarizing the results.\86\ At that time,
most of the data available was for pre-1998 model year onroad diesel
engines. The results are summarized in Table VIII.A.2-1. As shown, it
indicated that biodiesel tended to reduce emissions of VOC, CO and PM.
The NOX emission effect was more variable, showing a very
small increase on average.
---------------------------------------------------------------------------
\86\ ``A Comprehensive Analysis of Biodiesel Impacts on Exhaust
Emissions,'' Draft Technical Report, U.S. EPA, EPA420-P-02-001,
October 2002. http://www.epa.gov/otaq/models/biodsl.htm.
Table VIII.A.2-1.--Effect of 20 Vo% Biodiesel Blends on Diesel Emissions (%)
----------------------------------------------------------------------------------------------------------------
2002 draft Recent test results
Pollutant EPA study ---------------------------------------------------------------------
(percent) Engine testing Vehicle testing
----------------------------------------------------------------------------------------------------------------
VOC.......................... -21 -12% (-35% to +14%).............. +10% (-33% to +113%)
CO........................... -11 -14% (-28% to +1%)............... +4% (-11% to +44%)
NOX.......................... +2 +1% (-3% to +6%)................. +2% (-1% to +9%)
PM........................... -10 -20% (-31%+6%)................... -3% (-57% to +40%)
----------------------------------------------------------------------------------------------------------------
We collected relevant engine and vehicle emission test data
developed since the time of the 2002 study. The results of our analysis
of this data are also shown in Table VIII.A.2-1. There, we show the
average change in the emissions of each pollutant across all the
engines or vehicles tested, as well as the range of effects found for
each engine or vehicle. As can be seen, the variability in the emission
effects is quite large, but the results of the more recent testing
generally corroborate the findings of the 2002 study. Refer to DRIA
Tables 3.1-15 and 3.1-16, and their corresponding discussion, for more
detail on the data in the above table.
Overall, data indicating the effect of biodiesel on emissions is
still quite limited. The emission effects also appear to be dependent
on the load and speed of the engine (or driving cycle and vehicle type
in the case of vehicle testing). However, the data are too limited to
determine the specific way in which this occurs. Also, with the
implementation of stringent NOX and PM emission standards to
onroad and nonroad diesels in the 2007-2010 timeframe, any effect on a
percentage basis will rapidly decrease in magnitude on a mass basis as
base emission inventory level decreases. As additional testing is
performed over the next several years we will update this assessment.
3. Renewable Fuel Production and Distribution
The primary impact of renewable fuel production and distribution
regards ethanol, since it is expected to be the
[[Page 55620]]
predominant renewable fuel used in the foreseeable future. We
approximate the impact of increased ethanol and biodiesel production,
including corn and soy farming, on emissions based on DOE's GREET
model, version 1.6. We also include emissions related to distributing
the renewable fuels and take credit for reduced emissions related to
distributing displaced gasoline and diesel fuel. These emissions are
summarized in Table VIII.A.3-1.
Table VIII.A.3-1.--Well-to-Pump Emissions for Producing and Distributing
Renewable Fuels
[Grams per gallon ethanol or biodiesel] a
------------------------------------------------------------------------
Pollutant Ethanol Biodiesel
------------------------------------------------------------------------
VOC........................................... 3.6 41.5
CO............................................ 4.4 25.1
NOX........................................... 10.8 44.3
PM10.......................................... 6.1 1.5
SOX........................................... 7.2 7.5
------------------------------------------------------------------------
a Includes credit for reduced distribution of gasoline and diesel fuel.
At the same time, areas with refineries might experience reduced
emissions, not necessarily relative to current emission levels, but
relative to those which would have occurred in the future had renewable
fuel use not risen. However, to the degree that increased renewable
fuel use reduces imports of gasoline and diesel fuel, as opposed to the
domestic production of these fuels, these reduced refinery emissions
will occur overseas and not in the U.S.
Similarly, areas with MTBE production facilities might experience
reduced emissions from these plants as they cease producing MTBE.
However, many of these plants may be converted to produce other
gasoline blendstocks, such as iso-octane or alkylate. In this case,
their emissions are not likely to change substantially.
B. Impact on Emission Inventories
We use the NMIM to estimate emissions under the various ethanol
scenarios on a county by county basis. NMIM basically runs MOBILE6.2
and NONROAD2005 with county-specific inputs pertaining to fuel quality,
ambient conditions, levels of onroad vehicle VMT and nonroad equipment
usage, etc. We ran NMIM for two months, July and January. We estimate
annual emission inventories by summing the two monthly inventories and
multiplying by six.
As described above, we removed the effect of gasoline fuel quality
on exhaust VOC and NOX emissions from the onroad motor
vehicle inventories which are embedded in MOBILE6.2. We then applied
the exhaust emission effects from the EPA Predictive Models. In our
primary analysis, we only applied these EPA Predictive Model effects to
exhaust VOC and NOX emissions from Tier 0 vehicles. In a
sensitivity case, we applied them to exhaust VOC and NOX
emissions from all vehicles. Regarding the effect of fuel quality on
emissions of four air toxics from nonroad equipment (in terms of their
fraction of VOC emissions), in all cases we replaced the fuel effects
contained in NMIM with those for motor vehicles contained in MOBILE6.2.
The projected emission inventories for the primary analysis are
presented first, followed by those for the sensitivity analysis.
1. Primary Analysis
The national emission inventories for VOC, CO and NOX in
2012 with current fuels (i.e., ``reference fuel'') are summarized in
Table VIII.B.1-1. Also shown are the changes in emissions projected for
the two levels of ethanol use (i.e., ``control cases'') described in
Section VI and the two different cases for ethanol use in RFG.
Table VIII.B.1.-1.--2012 Emissions Nationwide From Gasoline Vehicles and Equipment Under Several Ethanol Use
Scenarios--Primary Analysis
[Tons per year]
----------------------------------------------------------------------------------------------------------------
Inventory Change in inventory in control cases
-------------------------------------------------------------------------------
7.2 Billion 9.6 Billion gallons of ethanol
gallons of -----------------------------------------------
Pollutant ethanol
Reference case ---------------- Maximum RFG Minimum RFG Maximum RFG
Minimum RFG use use use
use
----------------------------------------------------------------------------------------------------------------
VOC............................. 5,837,000 31,000 8,000 57,000 29,000
NOX............................. 2,576,000 19,000 20,000 40,000 39,000
CO.............................. 64,799,000 -843,000 -1,229,000 -1,971,000 -2,319,000
Benzene......................... 177,000 -6,000 -3,000 -11,000 -8,000
Formaldehyde.................... 40,200 300 0 800 500
Acetaldehyde.................... 19,800 6,200 5,000 9,600 8,500
1,3-Butadiene................... 18,200 -500 -300 -800 -600
----------------------------------------------------------------------------------------------------------------
Both VOC and NOX emissions are projected to increase
with increased use of ethanol. However, the increases are small,
generally less than 2 percent. Emissions of formaldehyde are also
projected to increase slightly, on the order of 1-3 percent. Emissions
of 1,3-butadiene and CO are projected to decrease by about 1-4 percent.
Benzene emissions are projected to decrease by 2-6 percent. The largest
change is in acetaldehyde emissions, an increase of 25-48 percent, as
acetaldehyde is a partial combustion product of ethanol.
CO also participates in forming ozone, much like VOCs. Generally,
CO is 15-50 times less reactive than typical VOC. Still, the reduction
in CO emissions is roughly 20-140 times the increase in VOC emissions
in the four scenarios. Thus, the projected reduction in CO emissions is
important from an ozone perspective. However, as described above, the
methodology for projecting the effect of ethanol use on CO emissions is
inconsistent with that for exhaust VOC and NOX emissions.
Thus, comparisons between changes in VOC and CO emissions are
particularly uncertain.
In addition to these changes in emissions due to ethanol use,
biodiesel use is expected to have a minor impact on diesel emissions.
Table VIII.B.1-2 shows the expected emission reductions associated with
an increase in biodiesel fuel use from the reference case of 28 million
gallons in 2012 to approximately 300 million gallons per year in 2012.
This represents an increase from 0.06 to 0.6 percent of onroad diesel
fuel consumption. In terms of a 20 percent biodiesel blend
[[Page 55621]]
(B20), it represents an increase from 0.3 to 3.2 percent of onroad
diesel fuel consumption.
Table VIII.B.1-2.--Annual Emissions Nationwide From Onroad Diesels in
2012
[Tons per year]
------------------------------------------------------------------------
Change in
Reference emissions
inventory: 28 Inventory: 300
mill gal mill gal
biodiesel per biodiesel per
year year
------------------------------------------------------------------------
VOC..................................... 135,000 -800
NOX..................................... 1,430,000 800
CO...................................... 353,000 -1,100
Fine PM................................. 27,000 -100
------------------------------------------------------------------------
As can be seen, the emission impacts due to biodiesel use are
roughly two orders of magnitude smaller than those due to ethanol use.
There will also be some increases in emissions due to ethanol and
biodiesel production. Table VIII.B.1-3 shows estimates of annual
emissions expected to occur nationwide due to increased production of
ethanol. These estimates include a reduction in emissions related to
the distribution of the displaced gasoline.
Table VIII.B.1-3.--Annual Emissions Nationwide From Ethanol Production and Transportation
[Tons per year]
----------------------------------------------------------------------------------------------------------------
Increase in emissions
-------------------------------
Reference 7.2 Billion 9.6 Billion
inventory gallons of gallons of
ethanol ethanol
----------------------------------------------------------------------------------------------------------------
VOC............................................................. 15,929 12,744 22,301
NOX............................................................. 47,716 38,173 66,802
CO.............................................................. 19,389 15,511 27,144
PM10............................................................ 27,094 21,675 37,931
SOX............................................................. 31,760 25,408 44,464
----------------------------------------------------------------------------------------------------------------
As can be seen, the potential increases in emissions from ethanol
production and transportation are of the same order of magnitude as
those from ethanol use, with the exception of CO emissions. The vast
majority of these emissions are related to farming and ethanol
production. Both farms and ethanol plants are generally located in
ozone attainment areas.
Table VIII.B.1-4 shows estimates of annual emissions expected to
occur nationwide due to increased production of biodiesel. These
estimates include a reduction in emissions related to the distribution
of the displaced diesel fuel.
Table VIII.B.1-4.--Annual Emissions Nationwide From Biodiesel Production
and Transportation
[Tons per year]
------------------------------------------------------------------------
Change in
Reference emissions
inventory: 28 Inventory: 300
Pollutant mill gal mill gal
biodiesel per biodiesel per
year year
------------------------------------------------------------------------
VOC..................................... 1,300 12,700
NOX..................................... 1,400 13,600
CO...................................... 800 7,200
PM10.................................... 50 1,000
SOX..................................... 200 1,800
------------------------------------------------------------------------
The potential emission increases related to biodiesel production
and distribution are generally much smaller, with the possible
exception of VOC emissions. Again, these emissions are generally
expected to be in ozone attainment areas.
2. Sensitivity Analysis
The national emission inventories for VOC and NOX in
2012 with current fuels are summarized in Table VIII.B.2-1. Here, the
emission effects contained in the EPA Predictive Models are assumed to
apply to all vehicles, not just Tier 0 vehicles. Also shown are the
changes in emissions projected for the two cases for future ethanol
volume and the two cases of ethanol use in RFG. CO emissions are the
same as in the primary analysis, as they are not affected by the EPA
Predictive Models.
[[Page 55622]]
Table VIII.B.2-1.--2012 Emissions Nationwide From Gasoline Vehicles and Equipment Under Several Ethanol Use
Scenarios: Sensitivity Analysis
[Tons per year]
----------------------------------------------------------------------------------------------------------------
Inventory Change in inventory in control cases
-------------------------------------------------------------------------------
7.2 Billion gallons of ethanol 9.6 Billion gallons of ethanol
Pollutant ---------------------------------------------------------------
Reference case Minimum RFG Maximum RFG Minimum RFG Maximum RFG
use use use use
----------------------------------------------------------------------------------------------------------------
VOC............................. 5,775,000 4,000 -8,000 14,000 -5,000
NOX............................. 2,610,000 49,000 45,000 95,000 89,000
CO.............................. 64,799,000 -843,000 -1,229,000 -1,971,000 -2,319,000
Benzene......................... 175,000 -9,000 -5,000 -14,000 - 10,000
Formaldehyde.................... 39,300 0 -200 300 0
Acetaldehyde.................... 19,200 5,800 4,700 9,000 8,000
1,3-Butadiene................... 17,900 -600 -400 -1,100 -800
----------------------------------------------------------------------------------------------------------------
The overall VOC and NOX emission impacts of the various
ethanol use scenarios change to some degree when all motor vehicles are
assumed to be sensitive to fuel ethanol content. The increase in VOC
emissions either decreases substantially or turns into a net decrease
due to a greater reduction in exhaust VOC emissions from onroad
vehicles. However, the increase in NOX emissions gets
larger, as more vehicles are assumed to be affected by ethanol.
Emissions of the four air toxics generally decrease slightly, due to
the greater reduction in exhaust VOC emissions.
3. Local and Regional VOC and NOX Emission Impacts in July
We also estimate the percentage change in VOC and NOX
emissions from gasoline fueled motor vehicles and equipment in those
areas which actually experienced a significant change in ethanol use.
Specifically, we focused on areas where the market share of ethanol
blends was projected to change by 50 percent or more. We also focused
on summertime emissions, as these are most relevant to ozone formation.
Finally, we developed separately estimates for: (1) RFG areas,
including the state of California and the portions of Arizona where
their CBG fuel programs apply, (2) low RVP areas (i.e., RVP standards
less than 9.0 RVP, and (3) areas with a 9.0 RVP standard. This set of
groupings helps to highlight the emissions impact of increased ethanol
use in those areas where emission control is most important.
Table VIII.B.3-1 presents our primary estimates of the percentage
change in VOC and NOX emission inventories for these three
types of areas. While ethanol use is going up in the vast majority of
the nation, ethanol use in RFG areas under the ``Minimum Use in RFG''
scenarios is actually decreasing compared to the 2012 reference case.
This is important to note in order to understand the changes in
emissions indicated.
Table VIII.B.3-1.--Change in Emissions From Gasoline Vehicles and Equipment in Counties Where Ethanol Use
Changed Significantly--Primary Analysis
----------------------------------------------------------------------------------------------------------------
Ethanol use 7.2 Billion gallons 9.6 Billion gallons
----------------------------------------------------------------------------------------------------------------
Ethanol use in RFG Minimum Maximum Minimum Maximum
----------------------------------------------------------------------------------------------------------------
RFG Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Down.............. Up................ Down.............. Up.
VOC............................. 1.6%.............. 0.4%.............. 1.6%.............. 0.4%.
NOX............................. -5.2%............. 2.4%.............. -5.2%............. 2.4%.
----------------------------------------------------------------------------------------------------------------
Low RVP Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 3.1%.............. 3.2%.............. 4.1%.............. 3.5%.
NOX............................. 4.1%.............. 6.0%.............. 4.8%.............. 4.4%.
----------------------------------------------------------------------------------------------------------------
Other Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 4.1%.............. 4.1%.............. 5.4%.............. 4.4%.
NOX............................. 4.6%.............. 6.0%.............. 5.8%.............. 4.8%.
----------------------------------------------------------------------------------------------------------------
As expected, increased ethanol use tends to increase NOX
emissions. The increase in low RVP and other areas is greater than in
RFG areas, since the RFG in the RFG areas included in this analysis all
contained MTBE. Also, increased ethanol use tends to increase VOC
emissions, indicating that the increase in non-exhaust VOC emissions
exceeds the reduction in exhaust VOC emissions. This effect is muted
with RFG due to the absence of an RVP waiver for ethanol blends. The
reader is referred to Chapter 2 of the DRIA for discussion of how
ethanol levels will change at the state-level.
Table VIII.B.3-2 presents the percentage change in VOC and
NOX
[[Page 55623]]
emission inventories under our sensitivity case (i.e., when we apply
the emission effects of the EPA Predictive Models to all motor
vehicles).
Table VIII.B.3-2.--Change in Emissions From Gasoline Vehicles and Equipment in Counties Where Ethanol Use
Changed Significantly--Sensitivity Analysis
----------------------------------------------------------------------------------------------------------------
7.2 Bgal Min 7.2 Bgal Max 9.6 Bgal Min 9.6 Bgal Max
----------------------------------------------------------------------------------------------------------------
RFG Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Down.............. Up................ Down.............. Up.
VOC............................. 2.6%.............. 0.2%.............. 2.6%.............. 0.2%.
NOX............................. -9.0%............. 4.7%.............. -9.0%............. 4.7%.
----------------------------------------------------------------------------------------------------------------
Low RVP Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 2.1%.............. 2.1%.............. 3.1%.............. 2.5%.
NOX............................. 8.2%.............. 10.6%............. 9.8%.............. 8.9%.
----------------------------------------------------------------------------------------------------------------
Other Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 3.4%.............. 3.4%.............. 4.6%.............. 3.7%.
NOX............................. 8.4%.............. 10.1%............. 10.3%............. 8.8%.
----------------------------------------------------------------------------------------------------------------
Directionally, the changes in VOC and NOX emissions in
the various areas are consistent with those from our primary analysis.
The main difference is that the increases in VOC emissions are smaller,
due to more vehicles experiencing a reduction in exhaust VOC emissions,
and the increases in NOX emissions are larger.
C. Impact on Air Quality
We estimate the impact of increased ethanol use on the ambient
concentrations of two pollutants: ozone and PM. Quantitative estimates
are made for ozone, while only qualitative estimates can be made
currently for ambient PM. These impacts are described below.
1. Impact of 7.2 Billion Gallon Ethanol Use on Ozone
We use a metamodeling tool developed at EPA, the ozone response
surface metamodel (Ozone RSM), to estimate the effects of the projected
changes in emissions from gasoline vehicles and equipment for the 7.2
billion gallon ethanol use case. The changes in diesel emissions are
negligible in comparison. We did not include the estimated changes in
emissions from renewable fuel production and distribution, because of
their more approximate nature. Their geographical concentration also
makes it more difficult to simulate with the Ozone RSM.
The Ozone RSM was created using multiple runs of the Comprehensive
Air Quality Model with Extensions (CAMx). Base and proposed control
CAMx metamodeling was completed for the year 2015 over a modeling
domain that includes all or part of 37 Eastern U.S. states, plus the
District of Columbia. For more information on the Ozone RSM, please see
the Chapter 5 of the DRIA for this proposal.
The Ozone RSM limits the number of geographically distinct changes
in VOC and NOX emissions which can be simulated. As a
result, we could not apply distinct changes in emissions for each
county. Therefore, two separate runs were made with different VOC and
NOX emissions reductions. We then selected the ozone impacts
from the various runs which best matched the VOC and NOX
emission reductions for that county. This models the impact of local
emissions reasonably well, but loses some accuracy with respect to
ozone transport. No ozone impact was assumed for areas which did not
experience a significant change in ethanol use. The predicted ozone
impacts of increased ethanol use for those areas where ethanol use is
projected to change by more than a 50% market share are summarized in
Table VIII.C.1-1. As shown in Table 5.1-2 of the DRIA, national average
impacts (based on the 37-state area modeled) which include those areas
where no change in ethanol use is occurring are considerably smaller.
Table VIII.C.1-1.--Impact on 8-hour Design Value Equivalent Ozone Levels (ppb) a
----------------------------------------------------------------------------------------------------------------
Primary Analysis Sensitivity Analysis
---------------------------------------------------
Min RFG Use Max RFG Use Min RFG Use Max RFG Use
----------------------------------------------------------------------------------------------------------------
Minimum Change.............................................. -0.030 -0.025 -0.180 0.000
Maximum Change.............................................. 0.395 0.526 0.637 0.625
Average Change b............................................ 0.137 0.171 0.294 0.318
Population-Weighted Change b................................ 0.134 0.129 0.268 0.250
----------------------------------------------------------------------------------------------------------------
a In comparison to the 80 ppb 8-hour ozone standards.
b Only for those areas experiencing a change in ethanol blend market share of at least 50 percent.
As can be seen, ozone levels generally increase to a small degree
with increased ethanol use. This is likely due to the projected
increases in both VOC and NOX emissions. Some areas do see a
small decrease in ozone levels. In our primary analysis, where exhaust
emissions from Tier 1 and later onroad vehicles are assumed to be
unaffected
[[Page 55624]]
by ethanol use, the population-weighted increase in ambient ozone
levels in those areas where ethanol use changed significantly is 0.129-
0.134 ppb. Since the 8-hour ambient ozone standard is 80 ppb, this
increase represents about 0.16 percent of the standard, a very small
percentage.
In our sensitivity analysis, where exhaust emissions from Tier 1
and later onroad vehicles are assumed to respond to ethanol like Tier 0
vehicles, the population-weighted increase in ambient ozone levels is
roughly twice as high, or 0.250-0.268 ppb. This increase represents
about 0.32 percent of the standard.
There are a number of important caveats concerning these estimates.
First, the emission effects of adding ethanol to gasoline are based on
extremely limited data for recent vehicles and equipment. Second, the
Ozone RSM does not account for changes in CO emissions. As shown above,
ethanol use should reduce CO emissions significantly, directionally
reducing ambient ozone levels in those areas where ozone formation is
VOC-limited. (Ozone levels in areas which are NOX-limited
are unlikely to be affected by a change in CO emissions.) The Ozone RSM
also does not account for changes in VOC reactivity. With additional
ethanol use, the ethanol content of VOC should increase. Ethanol is
less reactive than the average VOC. Therefore, this change should also
reduce ambient ozone levels in a way not addressed by the Ozone RSM,
again in those areas where ozone formation is predominantly VOC-
limited.
Moving to health effects, exposure to ozone has been linked to a
variety of respiratory effects including premature mortality, hospital
admissions and illnesses resulting in school absences. Ozone can also
adversely affect the agricultural and forestry sectors by decreasing
yields of crops and forests. Although the health and welfare impacts of
changes in ambient ozone levels are typically quantified in regulatory
impact analyses, we do not evaluate them for this analysis. On average,
the changes in ambient ozone levels shown above are small and would be
even smaller if changes in CO emissions and VOC reactivity were taken
into account. The increase in ozone would likely lead to negligible
monetized impacts. We therefore do not estimate and monetize ozone
health impacts for the changes in renewable use due to the small
magnitude of this change, and the uncertainty present in the air
quality modeling conducted here, as well as the uncertainty in the
underlying emission effects themselves discussed earlier.
2. Particulate Matter
Ambient PM can come from two distinct sources. First, PM can be
directly emitted into the atmosphere. Second, PM can be formed in the
atmosphere from gaseous pollutants. Gasoline-fueled vehicles and
equipment contribute to ambient PM concentrations in both ways.
As described above, we are not currently able to predict the impact
of fuel quality on direct PM emissions from gasoline-fueled vehicles or
equipment. Therefore, we are unable at this time to project the effect
that increased ethanol use will have on levels of directly emitted PM
in the atmosphere.
PM can also be formed in the atmosphere (termed secondary PM here)
from several gaseous pollutants emitted by gasoline-fueled vehicles and
equipment. Sulfur dioxide emissions contribute to ambient sulfate PM.
NOX emissions contribute to ambient nitrate PM. VOC
emissions contribute to ambient organic PM, particularly the portion of
this PM comprised of organic carbon. Increased ethanol use is not
expected to change gasoline sulfur levels, so emissions of sulfur
dioxide and any resultant ambient concentrations of sulfate PM are not
expected to change. Increased ethanol use is expected to increase
NOX emissions, as described above. Thus, the possibility
exists that ambient nitrate PM levels could increase. Increased ethanol
is generally expected to increase VOC emissions, which could also
impact the formation of secondary organic PM. However, some VOC
emissions, namely exhaust VOC emissions, are expected to decrease,
while non-exhaust VOC emissions are expected to increase and the impact
on PM is a function of the type of VOC emissions.
The formation of secondary organic PM is very complex, due in part
to the wide variety of VOCs emitted into the atmosphere. Whether or not
a specific gaseous VOC reacts to form PM in the atmosphere depends on
the types of reactions that VOC undergoes, which in turn can depend on
other pollutants present, such as ozone, NOX and other
reactive compounds. The relative mass of secondary PM formed per mass
of gaseous VOC emitted can also depend on the concentration of the
gaseous VOC and the organic PM in the atmosphere. Most of the secondary
organic PM exists in a continually changing equilibrium between the
gaseous and PM phases. Both the rates of these reactions and the
gaseous-PM equilibria depend on temperature, so seasonal differences
can be expected.
Recent smog chamber studies have indicated that gaseous aromatic
VOCs can form secondary PM under certain conditions. These compounds
comprise a greater fraction of exhaust VOC emissions than non-exhaust
VOC emissions, as non-exhaust VOC emissions are dominated by VOCs with
relatively high vapor pressures. Aromatic VOCs tend to have lower vapor
pressures. As increased ethanol use is expected to reduce exhaust VOC
emissions, emissions of aromatic VOCs should also decrease. In
addition, refiners are expected to reduce the aromatic content of
gasoline by 5 volume percentage points as ethanol is blended into
gasoline. Emissions of aromatic VOCs should decrease with lower
concentrations of aromatics in gasoline. Thus, emissions of gaseous
aromatic VOCs could decrease for both reasons.
Overall, we expect that the decrease in secondary organic PM is
likely to exceed the increase in secondary nitrate PM. In 1999,
NOX emissions from gasoline-fueled vehicles and equipment
comprised about 20% of national NOX emissions from all
sources. In contrast, gasoline-fueled vehicles and equipment comprised
over 60% of all national gaseous aromatic VOC emissions. The percentage
increase in national NOX emissions due to increased ethanol
use should be smaller than the percentage decrease in national
emissions of gaseous aromatics. Finally, in most urban areas, ambient
levels of secondary organic PM exceed those of secondary nitrate PM.
Thus, directionally, we expect a net reduction in ambient PM levels due
to increased ethanol use. However, we are unable to quantify this
reduction at this time.
EPA currently utilizes the CMAQ model to predict ambient levels of
PM as a function of gaseous and PM emissions. This model includes
mechanisms to predict the formation of nitrate PM from NOX
emissions. However, it does not currently include any mechanisms
addressing the formation of secondary organic PM. EPA is currently
developing a model of secondary organic PM from gaseous toluene
emissions. We plan to incorporate this mechanism into the CMAQ model in
2007. The impact of other aromatic compounds will be added as further
research clarifies their role in secondary organic PM formation.
Therefore, we expect to be able to quantitatively estimate the impact
of decreased toluene emissions and increased NOX emissions
due to
[[Page 55625]]
increased ethanol use as part of future analyses of U.S. fuel
requirements required by the Act.
IX. Impacts on Fossil Fuel Consumption and Related Implications
Renewable fuels have been of significant interest for many years
due to their ability to displace fossil fuels, which have often been
targeted as primary contributors to emissions of greenhouse gases such
as carbon dioxide and national energy concerns such as dependence on
foreign sources of petroleum. Because significantly more renewable fuel
is expected to be consumed over the next few years than has been
consumed in the past, there is increased interest in the degree to
which their increased use will impact greenhouse gas emissions and
fossil fuel consumption.
Based on our analysis, we estimate that increases in the use of
renewable fuels will reduce fossil fuel consumption and GHG emissions
as shown in Table IX-1 in 2012. The results represent the percent
reduction in total transportation sector emissions and energy use. The
ranges result from different cases evaluated of the amount of renewable
fuel (7.5 billion gallons versus 9.9 billion gallons) that will
actually be produced in 2012.
Table IX-1.--Lifecycle Impacts of Increased Renewable Fuel Use Relative
to the 2012 Reference Case
------------------------------------------------------------------------
7.5 Billion 9.9 Billion
case a case b
------------------------------------------------------------------------
Percent Reduction in Transportation Sector 1.0 1.6
Petroleum Energy Use.........................
Percent Reduction in Transportation Sector 0.5 0.8
Fossil Fuel Energy Use.......................
Percent Reduction in Transportation Sector GHG 0.4 0.6
Emissions....................................
Percent Reduction in Transportation Sector CO2 0.6 0.9
Emissions....................................
------------------------------------------------------------------------
a 7.2 billion gallons of ethanol.
b 9.6 billion gallons of ethanol.
This section provides a summary of our analysis of the fossil fuel
impacts of the RFS rule.
A. Lifecycle Modeling
Although the use of renewable fuels in the transportation sector
directly displaces some petroleum consumed as motor vehicle fuel, this
displacement of petroleum is in fact only one aspect of the overall
impact of renewable fuels on fossil fuel use. Fossil fuels are also
used in producing and transporting renewable feedstocks such as plants
or animal byproducts, in converting the renewable feedstocks into
renewable fuel, and in transporting and blending the renewable fuels
for consumption as motor vehicle fuel. To estimate the true impacts of
increases in renewable fuels on fossil fuel use, modelers attempt to
take many or all these steps into account. Similarly, energy is used
and GHGs emitted in the pumping of oil, transporting the oil to the
refinery, refining the crude oil into finished transportation fuel,
transporting the refined gasoline or diesel fuel to the consumer and
then burning the fuel in the vehicle. Such analyses are termed
lifecycle or well-to-wheels analyses.
A variety of approaches are available to conduct lifecycle
analysis. This variety largely reflects different assumptions about (1)
the boundary conditions and (2) the estimates of input factors. The
boundary conditions determine the scope of the analysis. For example, a
lifecycle analysis could include energy required to make farm equipment
as part of the estimate of energy required to grow corn. The agency
chose a lifecycle analytic boundary that encompasses the fuel-cycle and
does not include the example used above. Differing estimates on input
factors (e.g. amount of fertilizer to grow corn) can also affect the
results of the lifecycle analysis.
For this proposed rulemaking, we have made use of a fuel-cycle
model, GREET,\87\ developed at Argonne National Laboratory (ANL) under
the sponsorship of the U.S. Department of Energy's Office of Energy
Efficiency and Renewable Energy (EERE). GREET has been under
development for several years and has undergone extensive peer review
through multiple updates. Of the available sources of information on
lifecycle analyses of energy consumed and emissions generated, we
believe that GREET offers the most comprehensive treatment of the
transportation sector. For instance, GREET provides lifecycle
assessments for ethanol made from corn and cellulosic materials,
biodiesel made from soybean oil, and petroleum-based gasoline and
diesel fuel. Thus GREET provides a means for calculating the relative
greenhouse gas (GHG) and petroleum impacts of renewable fuels that
displace conventional motor vehicle fuels. For this proposal, we used
version 1.7 of the GREET model, with a few modifications to its input
assumptions as described in more detail below.
---------------------------------------------------------------------------
\87\ Greenhouse gases, Regulated Emissions, and Energy use in
Transportation.
---------------------------------------------------------------------------
We do not believe that it would be appropriate at this time to base
the regulatory provisions for this rule on lifecycle modeling, as
described in more detail in Section III.B.4. Although the GREET model
does provide a peer-reviewed source for lifecycle modeling, a consensus
on all the assumptions, including point estimates, that are used as
inputs into that model does not exist.\88\ Also, given the short
timeframe available for the development of this proposal, we have not
had the opportunity to initiate the type of public dialogue on
lifecycle modeling that would be necessary before such analyses could
be incorporated into a regulatory framework. We have therefore chosen
to use lifecycle modeling only as a means to estimate the impacts of
the increased use of renewable fuel.
---------------------------------------------------------------------------
\88\ See Chapter 6.1.2 of the RIA for further discussion of
input assumptions used for the GREET modeling. Also see IX.A.2 of
this preamble section for a discussion about the differing
estimates.
---------------------------------------------------------------------------
In addition to the GREET model tool, EPA has also developed a
lifecycle modeling tool that is specific to individual fuel producers.
This FUEL-CO2 model is intended to help fuel producers estimate the
lifecycle greenhouse gas emissions and fossil energy use for all stages
in the development of their specific fuel. EPA will evaluate whether
the FUEL-CO2 model would be an appropriate tool for fuel providers who
wish to demonstrate their actual reductions in greenhouse gas emissions
and fossil energy use. This may also be the best way for ethanol
producers to quantify the benefits of their renewable process energy
use when qualifying corn ethanol as cellulosic biomass ethanol (an
option for ethanol producers, stipulated in the Act).
[[Page 55626]]
1. Modifications to GREET Assumptions
GREET is subject to periodic updates by ANL, each of which results
in some changes to the inputs and assumptions that form the basis for
the lifecycle estimates of emissions generated and energy consumed.
These updates generally focus on those input values for those fuels or
vehicle technologies that are the focus of ANL at the time. As a result
there are a variety of other inputs related to ethanol and biodiesel
that have not been updated in some time. In the context of the RFS
program, we determined that some of the GREET input values that were
either based on outdated information or did not appropriately reflect
market conditions under a renewable fuels mandate should be examined
more closely, and updated if necessary.
In the timeframe available for developing this proposal, we chose
to concentrate our efforts on those GREET input values for ethanol that
had significant influence on the lifecycle emissions or energy
estimates and that were likely to be based on outdated information. We
reviewed the input values only for ethanol made from corn, since this
particular renewable fuel is likely to continue to dominate the
renewable fuel pool through at least 2012. For cellulosic ethanol and
biodiesel the GREET default values were used in this proposal. However,
we have also initiated a contract with ANL to investigate a wider
variety of GREET input values, including those associated with the
following fuel/feedstock pathways:
Ethanol from corn.
Ethanol from cellulosic materials (hybrid populars,
switchgrass, and corn stover).
Biodiesel from soybean oil.
Methanol from renewable sources.
Natural gas from renewable sources.
Renewable diesel formulations.
The contract focuses on the potential fuel production developments
and efficiency improvements that could occur within the time-frame of
the RFS program. The GREET input value changes resulting from this work
are projected to be available in the fall of 2006, not in time for this
proposal, but they will be incorporated into revised lifecycle
assessments for the final rule.
We did not investigate the input values associated with the
production of petroleum-based gasoline or diesel fuel in the GREET
model for this proposal. However, the refinery modeling discussed in
Section VII will provide some additional information on the process
energy requirements associated with the production of gasoline and
diesel under a renewable fuels mandate. We will use information from
this refinery modeling for the final rule to determine if any GREET
input values should be changed.
A summary of the GREET corn ethanol input values we investigated
and modified for this proposal is given below. We also examined several
other GREET input values, but determined that the default GREET values
should not be changed for a variety of reasons. These included ethanol
plant process efficiency, corn and ethanol transport distances and
modes, corn farming inputs, CO2 emissions from corn farming
land use change, and byproduct allocation methods. Our investigation of
these other GREET input values are discussed more fully in Chapter 6 of
the RIA. The current GREET default factors for these other inputs were
included in the analysis for this proposal.
a. Wet-Mill Versus Dry Mill Ethanol Plants. The two basic methods
for producing ethanol from corn are wet milling and dry milling. In the
wet milling process, the corn is soaked to separate the starch, used to
make ethanol, from the other components of the corn kernel. In the dry
milling process, the entire corn kernel is ground and fermented to
produce ethanol. The remaining components of the corn are then dried
for animal feed (dried distillers grains with solubles, or DDGS). Wet
milling is more complicated and expensive than dry milling, but it
produces more valuable products (ethanol plus corn syrup, corn oil, and
corn gluten meal and feeds). The majority of ethanol plants in the
United States are dry mill plants, which produce ethanol more simply
and efficiently. The GREET default is 70 percent dry mill, 30 percent
wet mill.
For this analysis, we expect most new ethanol plants will be dry
mill operations. That has been the trend in the last few years as the
demand for ethanol has grown, and our analysis of ethanol plants under
construction and planned for the near future has verified this.
Therefore, it was assumed that essentially all new ethanol facilities
would be dry mill plants.
b. Coal Versus Natural Gas in Ethanol Plants. The type of fuel used
within the ethanol plant for process energy, to power the various
components that are used in ethanol production (dryers, grinders,
heating, etc.) can vary among ethanol plants. The type of fuel used has
an impact on the energy usage, efficiency, and emissions of the plant,
and is primarily determined by economics. Most new plants built in the
last few years have used natural gas. Based on specific situations and
economics, some new plants are using coal. In addition, EPA is
promoting the use of combined heat and power, or cogeneration, in
ethanol plants to improve plant energy-efficiency and to reduce air
emissions. This technology, in the face of increasing natural gas
prices, may make coal a more attractive energy source for new ethanol
plants.
GREET assumes that 20 percent of plants will be powered by coal.
However, our review of plants under construction and those planned for
the near future indicates that coal will only be used for approximately
10% of the plants. This is the value we assumed in GREET for our
analysis. However, as new plants are constructed to meet the demands of
the RFS, this percentage is expected to go up. Future work in
preparation for the final rule will evaluate the potential trends for
combined heat and power and coal as process fuel.
c. Ethanol Production Yield. It is generally assumed that 1 bushel
of corn yields 2.7 gallons of ethanol. However, the development of new
enzymes continues to increase the potential ethanol yield. We used a
value of 2.71 gal/bu in our analysis. This value represents pure
ethanol production (i.e. no denaturant). This value is consistent with
the cost modeling of corn ethanol discussed in Section VII.
2. Controversy Concerning the Ethanol Energy Balance
Although we have made use of lifecycle impact estimates from ANL's
GREET model, there are a variety of lifecycle impact analyses from
other researchers that provide alternative and sometimes significantly
different estimates. The lifecycle energy balance for corn-ethanol, in
particular, has been the subject of numerous and sometimes contentious
debates.
Several metrics are commonly used to describe the energy efficiency
of renewable fuels. We have chosen to use displacement indexes for this
proposal because they provide the least ambiguous and most relevant
mechanism for estimating the impacts of renewable fuels on GHGs and
petroleum consumption. However, other metrics, such as the net energy
balance and energy efficiency, have more commonly been used in the
past. The use of these metrics has served to complicate the issue since
they do not involve a direct comparison to the gasoline that the
ethanol is replacing.
Among researchers who have studied the lifecycle energy balance of
corn-ethanol, the primary differences of opinion appear to center on
fossil energy associated with fertilizers, the
[[Page 55627]]
energy required to convert corn into ethanol, and the value of co-
products. As a result of these differences, the net energy balance has
been estimated to be somewhere between -34 and + 31 thousand Btu/gal,
and the energy efficiency has been estimated to be somewhere between
0.6 and 1.4.\89\ A concern arises in cases where a researcher concludes
that the net energy balance is negative, or the energy efficiency is
less than 1.0. Such cases would indicate that the fossil energy used in
the production and transportation of ethanol exceeds the energy in the
ethanol itself, and this is generally interpreted to mean that
lifecycle fossil fuel use negates the benefits of replacing gasoline
with ethanol. However, since the metrics used do not actually compare
ethanol to gasoline, such interpretations are unwarranted.
---------------------------------------------------------------------------
\89\ A net energy balance of zero, or an energy efficiency of
1.0, would indicate that the full lifecycle fossil fuels used in the
production and transportation of ethanol are exactly equal to the
energy in the ethanol itself.
---------------------------------------------------------------------------
The primary studies that conclude that the energy balance is
negative were conducted by Dr. David Pimental of Cornell University and
Dr. T. Patzek of University of California, Berkeley 90 91.
Many other researchers, however, have criticized that work as being
based on out-dated farming and ethanol production data, including data
not normally considered in lifecycle analysis for fuels, and not
following the standard methodology for lifecycle analysis in terms of
valuing co-products. Furthermore, several recent surveys have concluded
that the energy balance is positive, although they differ in their
numerical estimates.92 93 94 Authors of the GREET model have
also concluded that the lifecycle amount of fossil energy used to
produce ethanol is less than the amount of energy in the ethanol
itself. Based on our review of all the available information, we have
concluded that the energy balance is indeed positive, and we believe
that the GREET model provides an accurate basis for quantifying the
lifecycle impacts.
---------------------------------------------------------------------------
\90\ Pimentel, David ``Ethanol Fuel: Energy Balance, Economics,
and Environmental Impacts are Negative'', Vol. 12, No. 2, 2003
International Association for Mathematical Geology, Natural
Resources Research.
\91\ Pimentel, D.; Patzek, T. ``Ethanol production using corn,
switchgrass, and wood; biodiesel production using soybean and
sunflower.'' Nat. Resour. Res. 2005, 14 (1), 65-76.
\92\ Hammerschlag, R. ``Ethanol's Energy Return on Investment: A
Survey of the Literature 1990--Present.'' Environ. Sci. Technol.
2006, 40, 1744-1750.
\93\ Farrell, A., Pelvin, R., Turner, B., Joenes, A., O'Hare,
M., Kammen, D., ``Ethanol Can Contribute to Energy and Environmental
Goals'', Science, 1/27/2006, Vol. 311, 506-508.
\94\ Hill, J., Nelson, E., Tilman, D., Polasky, S., Tiffany, D.,
``Environmental, economic, and energetic costs and benefits of
biodiesel and ethanol biofuels'', Proceedings of the National
Academy of Sciences, 7/25/2006, Vol. 103, No. 30, 11206-11210.
---------------------------------------------------------------------------
B. Overview of Methodology
The GREET model does not provide estimates of energy consumed and
emissions generated in total, such as the total amount of natural gas
consumed in the U.S. in a given year by ethanol production facilities.
Instead, it provides estimates on a national average, per fuel unit
basis, such as the amount of natural gas consumed for the average
ethanol production facility per million Btus of ethanol produced. As a
result we could not use GREET directly to estimate the nationwide
impacts of replacing some gasoline and diesel with renewable fuels.
Instead, we used GREET to generate comparisons between renewable
fuels and the petroleum-based fuels that they displace. These
comparisons allowed us to develop displacement indexes that represent
the amount of lifecycle GHGs or fossil fuel reduced when a Btu of
renewable fuel replaces a Btu of gasoline or diesel. In order to
estimate the incremental impacts of increased use of renewable fuels on
GHGs and fossil fuels, we combined those displacement indexes with our
renewable fuel volume scenarios and GHG emissions and fossil fuel
consumption data for the conventional fuels replaced. For example, to
estimate the impact of corn-ethanol use on GHGs, these factors were
combined in the following way:
SGHG,corn ethanol = Rcorn ethanol x
LCgasoline x DIGHG,corn ethanol
Where:
SGHG,corn ethanol = Lifecycle GHG emission reduction
relative to the 2012 reference case associated with use of corn
ethanol (million tons of GHG).
Rcorn ethanol = Amount of gasoline replaced by corn
ethanol on an energy basis (Btu).
LCgasoline = Lifecycle emissions associated with gasoline
use (million tons of GHG per Btu of gasoline).
DIGHG,corn ethanol = Displacement Index for GHGs and corn
ethanol, representing the percent reduction in gasoline lifecycle
GHG emissions which occurs when a Btu of gasoline is replaced by a
Btu of corn ethanol.
Variations of the above equation were also generated for impacts on
all four endpoints of interest (emissions of CO2, emissions of GHGs,
fossil fuel consumption, and petroleum consumption) as well as all
three renewable fuels examined (corn-ethanol, cellulosic ethanol, and
biodiesel). Each of the variables in the above equation are discussed
in more detail below. Section 6 of the DRIA provides details of the
analysis.
1. Amount of Conventional Fuel Replaced by Renewable Fuel (R)
In general, the volume fraction (R) represents the amount of
conventional fuel no longer consumed--that is, displaced--as a result
of the use of the replacement renewable fuel. Thus R represents the
total amount of renewable fuel used under each of our renewable fuel
volume scenarios, in units of Btu. We make the assumption that vehicle
energy efficiency will not be affected by the presence of renewable
fuels (i.e., efficiency of combusting one Btu of ethanol is equal to
the efficiency of combusting one Btu of gasoline).
Consistent with the emissions modeling described in Section VII,
our analysis of the GHG and fossil fuel consumption impacts of
renewable fuel use was conducted using three volume scenarios. The
first scenario was a base case representing 2004 renewable fuel
production levels, projected to 2012. This scenario provided the point
of comparison for the other two scenarios. The other two renewable fuel
scenarios for 2012 represented the RFS program requirements and the
volume projected by EIA. In both scenarios, we assumed that the
biodiesel production volume would be 0.3 billion gallons based on an
EIA projection, and that the cellulosic ethanol production volume would
be 0.25 billion gallons based on the Energy Act's requirement that 250
million gallons of cellulosic ethanol be produced starting in the next
year, 2013. The remaining renewable fuel volumes in each scenario would
be ethanol made from corn. The total volumes for all three scenarios
are shown in Table IX.B.1-1. For the purposes of calculating the R
values, we assumed the ethanol volumes are 5% denatured, and the
volumes were converted to total Btu using the appropriate volumetric
energy content values (76,000 Btu/gal for ethanol, and 118,000 Btu/gal
for biodiesel).
[[Page 55628]]
Table IX.B.1-1.--Volume scenarios in 2012
[billion gallons]
------------------------------------------------------------------------
RFS
Reference required Projected
case volume: 7.5 volume: 9.9
B gal B gal
------------------------------------------------------------------------
Corn-ethanol.................. 3.9 6.95 9.35
Cellulosic ethanol............ 0.0 0.25 0.25
Biodiesel..................... 0.028 0.3 0.3
-----------------------------------------
Total volume.............. 3.928 7.5 9.9
------------------------------------------------------------------------
Since the impacts of increased renewable fuel use were measured
relative to the 2012 reference case, the value of R actually
represented the incremental amount of renewable fuel between the
reference case and each of the two other scenarios.
2. Lifecycle Impacts of Conventional Fuel Use (LC)
In order to determine the lifecycle impact that increased renewable
fuel volumes may have on any particular endpoint (fossil fuel
consumption or emissions of GHGs), we also needed to know the
conventional fuel inventory on a lifecycle basis. Since available
sources of GHG emissions are provided on a direct rather than a
lifecycle basis, we converted these direct emission and energy
estimates into their lifecycle counterparts. We used GREET to develop
multiplicative factors for converting direct (vehicle-based) emissions
of GHGs and energy use into full lifecycle factors. Table IX.B.2-1
shows the total lifecycle petroleum and GHG emissions associated with
direct use of a Btu value of gasoline and diesel fuel.
Table IX.B.2-1.--Lifecycle Emissions and Energy (LC Values)
------------------------------------------------------------------------
Gasoline Diesel
------------------------------------------------------------------------
Petroleum (Btu/Btu)........................... 1.11 1.10
Fossil fuel (Btu/Btu)......................... 1.22 1.21
GHG (Tg-CO2-eq/QBtu).......................... 99.4 94.5
CO2 (Tg-CO2/QBtu)............................. 94.2 91.9
------------------------------------------------------------------------
3. Displacement Indexes (DI)
The displacement index (DI) represents the percent reduction in GHG
emissions or fossil fuel energy brought about by the use of a renewable
fuel in comparison to the conventional gasoline or diesel that the
renewable fuel replaces. The formula for calculating the displacement
index depends on which fuel is being displaced (i.e. gasoline or
diesel), and which endpoint is of interest (e.g. petroleum energy,
GHG). For instance, when investigating the CO2 impacts of
ethanol used in gasoline, the displacement index is calculated as
follows:
[GRAPHIC] [TIFF OMITTED] TP22SE06.005
The units of g/Btu ensure that the comparison between the renewable
fuel and the conventional fuel is made on a common basis, and that
differences in the volumetric energy content of the fuels is taken into
account. The denominator includes the CO2 emitted through
combustion of the gasoline itself in addition to all the CO2
emitted during its manufacturer and distribution. The numerator, in
contrast, includes only the CO2 emitted during the
manufacturer and distribution of ethanol, not the CO2
emitted during combustion of the ethanol.
The combustion of biomass-based fuels, such as ethanol from corn
and woody crops, generates CO2. However, in the long run the
CO2 emitted from biomass-based fuels combustion does not
increase atmospheric CO2 concentrations, assuming the
biogenic carbon emitted is offset by the uptake of CO2
resulting from the growth of new biomass. As a result, CO2
emissions from biomass-based fuels combustion are not included in their
lifecycle emissions results and are not used in the CO2
displacement index calculations shown above.
Using GREET, we calculated the lifecycle values for energy consumed
and GHGs produced for corn-ethanol, cellulosic ethanol, and soybean-
based biodiesel. These values were in turn used to calculate the
displacement indexes. The results are shown in Table IX.B.3-1. Details
of these calculations can be found in Chapter 6 of the RIA. As noted
previously, different models can result in different estimates. For
example, whereas GREET estimates a net GHG reduction of about 26% for
corn ethanol compared to gasoline, the previously cited works by
Farrell et al. estimates around a 13% reduction.
Table IX.B.3-1.--Displacement Indexes Derived From GREET
----------------------------------------------------------------------------------------------------------------
Cellulosic
Corn ethanol ethanol Biodiesel
(percent) (percent) (percent)
----------------------------------------------------------------------------------------------------------------
DIPetroleum..................................................... 92.3 92.7 84.6
DIFossil Fuel................................................... 40.1 96.0 47.9
DIGHG........................................................... 25.8 98.1 53.4
[[Page 55629]]
DICO2........................................................... 43.9 110.1 56.8
----------------------------------------------------------------------------------------------------------------
The displacement indexes in this table represent the impact of
replacing a Btu of gasoline or diesel with a Btu of renewable fuel.
Thus, for instance, for every Btu of gasoline which is replaced by corn
ethanol, the total lifecycle GHG emissions that would have been
produced from that Btu of gasoline would be reduced by 25.8 percent.
For every Btu of diesel which is replaced by biodiesel, the total
lifecycle petroleum energy that would have been consumed as a result of
burning that Btu of diesel fuel would be reduced by 84.6 percent.
Note that our DI estimates for cellulosic ethanol assume that the
ethanol in question was in fact produced from a cellulosic feedstock,
such as wood, corn stalks, or switchgrass. However, the definition of
cellulosic biomass ethanol given in the Energy Act also includes
ethanol made from non-cellulosic feedstocks if 90 percent of the
process energy used to operate the facility is derived from a renewable
source. In the context of our cost analysis, we have assumed this
latter definition of cellulosic ethanol. Further discussion of this
issue can be found in Chapter 1, Section 1.2.2 of the RIA.
C. Impacts of Increased Renewable Fuel Use
We used the methodology described above to calculate impacts of
increased use of renewable fuels on consumption of petroleum and fossil
fuels and also on emissions of CO2 and GHGs. This section
describes our results.
1. Fossil Fuels and Petroleum
We used the equation for S above to calculate the reduction
associated with the increased use of renewable fuels on lifecycle
fossil fuels and petroleum. These values are then compared to the total
U.S. transportation sector emissions to get a percent reduction. The
results are presented in Tables IX.C.1-1 and IX.C.1-2.
Table IX.C.1.-1.--Fossil Fuel Impacts of Increased Use of Renewable
Fuels in the Transportation Sector in 2012, Relative to the 2012
Reference Case
------------------------------------------------------------------------
RFS Required Projected
volume: 7.5 volume: 9.9
Bgal Bgal
------------------------------------------------------------------------
Reduction (quadrillion Btu)............. 0.2 0.3
Percent reduction....................... 0.5 0.8
------------------------------------------------------------------------
Table IX.C.1.-2.--Petroleum Impacts of Increased Use of Renewable Fuels
in the Transportation Sector in 2012, Relative to the 2012 Reference
Case
------------------------------------------------------------------------
RFS Required Projected
volume: 7.5 volume: 9.9
Bgal Bgal
------------------------------------------------------------------------
Reduction (billion gal)................. 2.3 3.9
Percent reduction....................... 1.0 1.6
------------------------------------------------------------------------
2. Greenhouse Gases and Carbon Dioxide
One issue that has come to the forefront in the assessment of the
environmental impacts of transportation fuels relates to the effect
that the use of such fuels could have on emissions of greenhouse gases
(GHGs). The combustion of fossil fuels has been identified as a major
contributor to the increase in concentrations of atmospheric carbon
dioxide (CO2) since the beginning of the industrialized era,
as well as the build-up of trace GHGs such as methane (CH4)
and nitrous oxide (N2O). This lifecycle analysis evaluates
the impacts of renewable fuel use on greenhouse gas emissions.
The relative global warming contribution of emissions of various
greenhouse gases is dependant on their radiative forcing, atmospheric
lifetime, and other considerations. For example, on a mass basis, the
radiative forcing of CH4 is much higher than that of
CO2, but its effective atmospheric residence time is much
lower. The relative warming impacts of various greenhouse gases, taking
into account factors such as atmospheric lifetime and direct warming
effects, are reported on a CO2-equivalent basis as global
warming potentials (GWPs). The GWPs used by GREET were developed by the
UN Intergovernmental Panel on Climate Change (IPCC) as listed in their
Third Assessment Report \95\, and are shown in Table IX.C.2-1.
---------------------------------------------------------------------------
\95\ IPCC ``Climate Change 2001: The Scientific Basis'', Chapter
6; Intergovernmental Panel on Climate Change; J. T. Houghton, Y.
Ding, D. J. Griggs, M. Noguer, P. J. van der Linden, X. Dai, C. A.
Johnson; and K. Maskell, eds.; Cambridge University Press.
Cambridge, U. K. 2001. http://www.grida.no/climate/ipcc_tar/wg1/index.htm.
Table IX.C.2-1.--Global Warming Potentials for Greenhouse Gases
------------------------------------------------------------------------
Greenhouse gas GWP
------------------------------------------------------------------------
CO2.......................................................... 1
CH4.......................................................... 23
N2O.......................................................... 296
------------------------------------------------------------------------
Greenhouse gases are measured in terms of CO2-equivalent
emissions, which result from multiplying the GWP for each of the three
pollutants shown in the above table by the mass of emission for each
pollutant. The sum of
[[Page 55630]]
impacts for CH4, N2O, and CO2, yields
the total effective GHG impact.
We used the equation for S above to calculate the reduction
associated with the increased use of renewable fuels on lifecycle
emissions of CO2. These values are then compared to the
total U.S. transportation sector emissions to get a percent reduction.
The results are presented in Table IX.C.2-2.
Table IX.C.2-2.--CO2 Emission Impacts of Increased Use of Renewable Fuels in the Transportation Sector in 2012,
Relative to the 2012 Reference Case
----------------------------------------------------------------------------------------------------------------
RFS Required volume: Projected Volume: 9.9
7.5 Bgal Bgal
----------------------------------------------------------------------------------------------------------------
Reduction (million metric tons CO2) 12.6 19.8
Percent reduction 0.6 % 0.9 %
----------------------------------------------------------------------------------------------------------------
Carbon dioxide is a subset of GHGs, along with CH4 and
N2O as discussed above. It can be seen from Table IX.B.3-1
that the displacement index of CO2 is greater than for GHGs
for each renewable fuel. This indicates that lifecycle emissions of
CH4 and N2O are higher for renewable fuels than
for the conventional fuels replaced. Therefore, reductions associated
with the increased use of renewable fuels on lifecycle emissions of
GHGs are lower than the values for CO2. The results for GHGs
are presented in Table IX.C.2-3.
Table IX.C.2-3.--GHG Emission Impacts of Increased Use of Renewable
Fuels in the Transportation Sector in 2012, Relative to the 2012
Reference Case
------------------------------------------------------------------------
RFS
Required Projected
volume: 7.5 Volume: 9.9
Bgal Bgal
------------------------------------------------------------------------
Reduction (million metric tons CO2-eq.)....... 9.0 13.5
Percent reduction............................. 0.4% 0.6%
------------------------------------------------------------------------
D. Implications of Reduced Imports of Petroleum Products
This section only considers the impacts on imports of oil and
petroleum products. Expanded production and use of renewable fuels
could have other economic impacts such as on the exports of
agricultural products like corn. See section X of the preamble for a
discussion on agricultural sector impacts.
In 2005, the United States imported almost 60 percent of the oil it
consumed. This compares to just over 35 percent oil imports in
1975.\96\ Transportation accounts for 70% of the U.S. oil consumption.
It is clear that oil imports have a significant impact on the U.S.
economy. Expanded production of renewable fuel is expected to
contribute to energy diversification and the development of domestic
sources of energy. We consider whether the RFS will reduce U.S.
dependence on imported oil by calculating avoided expenditures on
petroleum imports. Note that we do not calculate whether this reduction
is socially beneficially, which would depend on the scarcity value of
domestically produced ethanol versus that of imported petroleum
products.
---------------------------------------------------------------------------
\96\ Davis, Stacy C.; Diegel, Susan W., Transportation Energy
Data Book: 25th Edition, Oak Ridge National Laboratory, U.S.
Department of Energy, ORNL-6974, 2006.
---------------------------------------------------------------------------
To assess the impact of the RFS program on petroleum imports, the
fraction of domestic consumption derived from foreign sources was
estimated using results from the AEO 2006. In section 6.4.1 of the DRIA
we describe how fuel producers change their mix in response to a
decrease in fuel demand. We do not expect the projected reductions in
petroleum consumption (0.3 to 0.57 Quads) to impact world oil prices by
a measurable amount. We base this assumption on the overall size of
worldwide petroleum demand and analysis of the AEO 2006 cases. As a
consequence, domestic crude oil production for the 7.5 or 9.9 cases
would not be expected to change significantly versus the RFS reference
case. Thus, petroleum reductions will come largely from reductions in
net petroleum imports. This conclusion is confirmed by comparing the
AEO 2006 low macroeconomic growth case to the AEO 2006 reference case,
as discussed in the RIA 6.4.1. The AEO 2006 shows that for a reduction
in petroleum demand on the order of the reductions estimated for the
RFS, net imports will account for approximately 95% of the reductions.
However, if petroleum reductions were large enough to impact world oil
prices, the mix of domestic crude oil, imports of finished products,
and imports of crude oil used by fuel producers would change. We
discuss this uncertainty in more detail in section 6.4.1 of the RIA and
solicit comments to the extent by which the RFS may have a price effect
and impact the imports of crude oil and refined products.
We quantified the fraction of net petroleum imports that would be
crude oil versus finished products. Comparison of same cases in the AEO
2006 shows that finished products initially compose all the net import
reductions, followed by imported crude oil once reductions in
consumption reach beyond 1.2 Quads of petroleum product. However, there
is significant uncertainty in quantifying how refineries will change
their mix of sources with a decrease in petroleum demand, particularly
at the levels estimated for the RFS. For example, a comparison between
the AEO low price case (as opposed to low macroeconomic growth case)
and the reference case would yield a 50-50 split between product and
crude imports. We believe that the actual refinery response could range
between these two points, so that finished product imports would
compose between 50 to 100% of the net import reductions, with crude oil
imports making up the remainder. For the purposes of this rulemaking,
we show values for the case where net import reductions come entirely
from imports of finished products, as shown below in Table IX.D-1. We
compare these reductions in imports against the AEO projected levels of
net petroleum imports. The range of reductions in net petroleum imports
are estimated to be between 1 to 2%, as shown in Table IX.D-2.
Table IX.D-1.--Reductions in Imports of Finished Products
[barrels per day]
------------------------------------------------------------------------
Cases 2012
------------------------------------------------------------------------
7.5........................................................ 145,454
9.9........................................................ 240,892
------------------------------------------------------------------------
[[Page 55631]]
Table IX.D-2.--Percent Reductions in Petroleum Imports Compared to
AEO2006 Import Projections
------------------------------------------------------------------------
Cases 2012
------------------------------------------------------------------------
7.5............................................................ 1.1%
9.9............................................................ 1.7%
------------------------------------------------------------------------
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
potential disruption in supply or spike in cost of a particular energy
source is reduced.
To understand the energy security implications of the RFS, EPA will
work with Oak Ridge National Laboratory (ORNL). As a first step, ORNL
will update and apply the approach used in the 1997 report Oil Imports:
An Assessment of Benefits and Costs, by Leiby, Jones, Curlee and
Lee.\97\ This paper was cited and its results utilized in previous DOT/
NHTSA rulemakings, including the 2006 Final Regulatory Impact Analysis
of CAFE Reform for Light Trucks.\98\ This approach is consistent with
that used in the Effectiveness and Impact of Corporate Average Fuel
Economy (CAFE) Standards Report conducted by the National Research
Council/National Academy of Sciences in 2002. Both reports estimate the
marginal benefits to society, in dollars per barrel, of reducing either
imports or consumption. This ``oil premium'' approach emphasizes
identifying those energy-security related costs that are not reflected
in the market price of oil, and which may change in response to an
incremental change in the level of oil imports or consumption.\99\
---------------------------------------------------------------------------
\97\ Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and
Russell Lee,Oil Imports: An Assessment of Benefits and Costs, ORNL-
6851, Oak Ridge National Laboratory, November 1, 1997. (http://pzl1.ed.ornl.gov/energysecurity.html).
\98\ US DOT, NHTSA 2006. ``Final Regulatory Impact
Analysis:Corporate Average Fuel Economy and CAFE Reform for MY 2008-
2011 Light Trucks,'' Office of Regulatory Analysis and Evaluation,
National Center for Statistics and Analysis, March. (http://www.nhtsa.dot.gov/staticfiles/DOT/NHTSA/Rulemaking/Rules/Associated%20Files/2006_FRIAPublic.pdf).
\99\ For instance, the 1997 ORNL study gave a range for the
``oilpremium'' $0 to $13 per barrel (adjusted to $2004) based on
1994 market conditions. The actual value depended on assumptions
about the market power of foreign exporters and the monopsony power
of the U.S., the risk of future oil price shocks and the employment
of hedging strategies, and the connections between oil shocks and
GNP.
---------------------------------------------------------------------------
Since the 1997 publication of this report changes in oil market
conditions, both current and projected, suggest that the magnitude of
the ``oil premium'' may have changed. Significant factors that should
be reconsidered include: Oil prices, current and anticipated levels of
OPEC production, U.S. import levels, potential OPEC behavior and
responses, and disruption likelihoods. ORNL will apply the most
recently available careful quantitative assessment of disruption
likelihoods, from the Stanford Energy Modeling Forum's 2005 workshop
series, as well as other assessments \100\. ORNL will also revisit the
issue of the macroeconomic consequences of oil market disruptions and
sustained higher oil prices. Using the ``oil premium'' calculation
methodology which combines short-run and long-run costs and benefits,
and accounting for uncertainty in the key driving factors, ORNL will
provide an updated range of estimates of the marginal energy security
implications of displacing oil consumption with renewable fuels. The
results of this work effort are not available for this proposal but
will be part of the assessment of impacts of the RFS in the final rule.
Although not directly applicable, financial economics literature has
examined risk diversification. The agency is interested in ways to
examine changes in risks associated with diversifying energy sources in
general and solicits comments as such.
---------------------------------------------------------------------------
\100\ Stanford Energy Modeling Forum, Phillip C. Beccue and
Hillard G.Huntington, 2005. ``An Assessment of Oil Market Disruption
Risks,'' FINAL REPORT, EMF SR 8, October 3. (http://www.stanford.edu/group/EMF/publications/search.htm).
---------------------------------------------------------------------------
We also calculate the decreased expenditures on petroleum imports
and compare this with the U.S. trade position measured as U.S. net
exports of all goods and services economy-wide. All reductions in
petroleum imports are expected to be from finished petroleum products
rather than crude oil. The reduced expenditures in petroleum product
imports were calculated by multiplying the reductions in gasoline and
diesel imports by their corresponding price. According to the EIA, the
price of imported finished products is the market price minus domestic
local transportation from refineries and minus taxes.\101\ An estimate
was made by using the AEO 2006 gasoline and distillate price forecasts
and subtracting the average Federal and state taxes based on historical
data.\102\
---------------------------------------------------------------------------
\101\ EIA (September 1997), ``Petroleum 1996: Issues and
Trends'', Office of Oil and Gas, DOE/EIA-0615, p. 71. (http://tonto.eia.doe.gov/FTPROOT/petroleum/061596.pdf)
\102\ The average taxes per gallon of gasoline and diesel have
stayedrelatively constant. For 2000-2006, gasoline taxes were $0.44/
gallon ($2004) while for 2002-2006, diesel taxes were $0.49/gallon.
The average was taken from available EIA data (http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp).
---------------------------------------------------------------------------
We compare these avoided petroleum import expenditures against the
projected value of total U.S. net exports of all goods and services
economy-wide. Net exports is a measure of the difference between the
value of exports of goods and services by the U.S. and the value of
U.S. imports of goods and services from the rest of the world. For
example, according to the AEO 2006, the value of total import
expenditures of goods and services exceeds the value of U.S. exports of
goods and services to the rest of the world by $695 billion for 2006
(for a net export level of minus $695 billion).\103\ This net exports
level is projected to diminish to minus $383 billion by 2012. In Table
IX.D-3, we compare the avoided expenditures in petroleum imports versus
the total value of U.S. net exports of goods and services for the whole
economy for 2012. Relative to the 2012 projection, the avoided
petroleum expenditures due to the RFS would represent 0.9 to 1.5% of
economy-wide net exports.
---------------------------------------------------------------------------
\103\ For reference, the U.S. Bureau of Economic Analysis (BEA)
reports that the 2005 import expenditures. on energy-related
petroleum products totaled $235.5 billion (2004$) while petroleum
exports totaled $13.6 billion--for a net of $221.9 billion in
expenditures. Net petroleum expenditures made up a significant
fraction of the $591.3 billion current account deficit in goods and
services for 2005 (2004$). (http://www.bea.gov/)
[[Page 55632]]
Table IX.D-3.--Avoided Petroleum Import Expenditures for 2012
[$2004 billion]
------------------------------------------------------------------------
Percent
Avoided versus
AEO2006 total net exports RFS Cases expenditures total net
in petroleum exports
imports (Percent)
------------------------------------------------------------------------
-$383........................... 7.5 3.5 0.9
9.9 5.8 1.5
------------------------------------------------------------------------
X. Agricultural Sector Economic Impacts
As described in more detail in the Draft Regulatory Impact Analysis
accompanying this proposal, we plan to evaluate the economic impact on
the agricultural sector. However, due to the timing of that analysis,
it will not be completed until the final rule. In the meantime, we
briefly describe here (and in more detail in the draft RIA) our planned
analyses and the sources of assumptions which could critically impact
those assessments. Finally, we ask for specific comment on the best
sources of information we use in these analyses.
We will be using the Forest and Agricultural Sector Optimization
Model (``FASOM'') developed over the past 30 years by Bruce McCarl,
Texas A&M University and others. This is a constrained optimization
model which seeks to allocate resources and production to maximize
producer plus consumer surpluses. We have consulted with a range of
experts both within EPA as well as at our sister agencies, the U.S.
Departments of Agriculture and Energy and they support the use of this
model for assessing the economic impacts on the agricultural sector of
various renewable fuel pathways evaluated in this rule. The objective
of this modeling assessment is to predict the economic impacts that
will directly result from the expanded use of farm products for
transportation fuel production. We anticipate that the growing demand
for corn for ethanol production in particular but also soybeans and
other agricultural crops such as rapeseed and other oil seeds for
biodiesel production will increase the production of these feedstocks
and impact farm income. The additional corn to produce ethanol may come
from several sources, including (1) more intensive cultivation of
existing land that currently produces corn, (2) switching production
from soybean and cotton to corn, (3) additional acres of land being
cultivated, or (4) diversion from corn exports. The implications to
U.S. net exports and environment effects partially depend on which
source supplies more corn. Eventually various cellulose sources such as
corn stover and switchgrass for cellulose-based ethanol production may
well become highly demanded and also significantly impact the
agricultural sector.
Using the FASOM model, we will estimate the direct impact on farm
income resulting from higher demand for corn and soybeans, for example.
Additionally, we will estimate impacts on farm employment. Since we
expect the higher demand for feedstock will increase both the supply
and cost of feedstock, we will also consider how the higher renewable
fuel feedstock cost impacts the cost of other agricultural products
(corn and soy meal are important sources not only for directly making
food for human consumption but also as feed for farm animals). As an
estimate of the impact on corn and soybeans prices, we are relying on
the estimates provided by the U.S. Department of Agriculture \104\
rather than using the FASOM model to derive these price impacts.
Additionally, we will rely on the Energy Information Agency's estimates
for fuel mix in predicting the amount of ethanol and biodiesel in the
fuel pool. Other than these external constraints, we expect to use
FASOM as the basic model for estimating economic impacts on farm sector
and how these might more generally impact the U.S. economy. Note that
this FASOM analysis is a partial equilibrium analysis, focusing almost
exclusively on impacts in the U.S. agricultural sector. As a result, it
cannot be utilized to make broader assessments of net social benefits
resulting from this rulemaking, which for example would require
evaluation of the transfer payments to farmers and ethanol producers
from consumers and refiners.
---------------------------------------------------------------------------
\104\ ``USDA Agricultural Baseline Projections to 2015.''
---------------------------------------------------------------------------
XI. Public Participation
We request comments on all aspects of this proposal. The comment
period for this proposed rule will be November 12, 2006. Comments can
be submitted to the Agency through any of the means listed under
ADDRESSES above.
We will hold a public hearing on October 13, 2006. The public
hearing will start at 10 a.m. (Central) at the Sheraton Gateway Suites
Chicago O'Hare, 6501 North Mannheim Road, Rosemont, Illinois 60018. If
you would like to present testimony at the public hearing, we ask that
you notify the contact person listed under FOR FURTHER INFORMATION
CONTACT above at least ten days beforehand. You should estimate the
time you will need for your presentation and identify any needed audio/
visual equipment. We suggest that you bring copies of your statement or
other material for the EPA panel and the audience. It would also be
helpful if you send us a copy of your statement or other materials
before the hearing.
We will arrange for a written transcript of the hearing and keep
the official record of the hearing open for 30 days to allow for the
public to supplement the record. You may make arrangements for copies
of the transcript directly with the court reporter.
XII. Administrative Requirements
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866, (58 FR 51735, October 4, 1993)
this action is a ``significant regulatory action'' because of the
policy implications of the proposed rule. Even though EPA has estimated
that renewable fuel use through 2012 will be sufficient to meet the
levels required in the standard, the proposed rule reflects the first
renewable fuel mandate at the Federal level. Accordingly, EPA submitted
this action to the Office of Management and Budget (OMB) for review
under EO 12866 and any changes made in response to OMB recommendations
have been documented in the docket for this action.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction
[[Page 55633]]
Act, 44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by EPA has been assigned EPA ICR number 2242.01.
The information is planned to be collected to ensure that the
required amount of renewable fuel is used each year. The credit trading
program required by the Energy Act will be satisfied through a program
utilizing Renewable Identification Numbers (RIN), which serve as a
surrogate for renewable fuel consumption. Our proposed RIN-based
program would fulfill all the functions of a credit trading program,
and thus would meet the Energy Act's requirements. For each calendar
year, each obligated party would be required to submit a report to the
Agency documenting the RINs it acquired, and showing that the sum of
all RINs acquired were equal to or greater than its renewable volume
obligation. The Agency could then verify that the RINs used for
compliance purposes were valid by simply comparing RINs reported by
producers to RINs claimed by obligated parties. The Agency will then
calculate the total amount of renewable fuel produced each year.
For fuel standards, Section 208(a) of the Clean Air Act requires
that manufacturers provide information the Administrator may reasonably
require to determine compliance with the regulations; submission of the
information is therefore mandatory. We will consider confidential all
information meeting the requirements of Section 208(c) of the Clean Air
Act.
The annual public reporting and recordkeeping burden for this
collection of information is estimated to be 3.1 hours per response.
Burden means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency. This includes the time needed
to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements
which have subsequently changed; train personnel to be able to respond
to a collection of information; search data sources; complete and
review the collection of information; and transmit or otherwise
disclose the information.
A document entitled ``Information Collection Request (ICR); OMB-83
Supporting Statement, Environmental Protection Agency, Office of Air
and Radiation,'' has been placed in the public docket. The supporting
statement provides a detailed explanation of the Agency's estimates by
collection activity. The estimates contained in the docket are briefly
summarized here:
Estimated total number of potential respondents: 4,945.
Estimated total number of responses: 4,970.
Estimated total annual burden hours: 15,560.
Estimated total annual costs: $2,911,000, including $1,806,240 in
purchased services.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this rule, which
includes this ICR, under Docket ID number EPA-OAR-2005-0161. Submit any
comments related to the ICR for this proposed rule to EPA and OMB. See
the ADDRESSES section at the beginning of this notice for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after publication in the Federal Register, a
comment to OMB is best assured of having its full effect if OMB
receives it by October 30, 2006. The final rule will respond to any OMB
or public comments on the information collection requirements contained
in this proposal.
C. Regulatory Flexibility Act
1. Overview
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201 (see table below); (2) a small governmental jurisdiction that
is a government of a city, county, town, school district or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field. The
following table provides an overview of the primary SBA small business
categories potentially affected by this regulation:
----------------------------------------------------------------------------------------------------------------
NAICS
Industry Defined as small entity by SBA if: codes\a\
----------------------------------------------------------------------------------------------------------------
Gasoline refiners............................... <=1,500 employees and a crude capacity of 324110
<=125,000 bpcd\b\.
----------------------------------------------------------------------------------------------------------------
\a\ North American Industrial Classification System.
\b\ barrels of crude per day.
2. Background--Small Refiners Versus Small Refineries
Title XV (Ethanol and Motor Fuels) of the Energy Policy Act
provides, at Section 1501(a)(2) [42 U.S.C. 7545(o)(9)(A)-(D)], special
provisions for ``small refineries'', such as a temporary exemption from
the standards until calendar year 2011. The Act defines the term
``small refinery'' as ``* * * a refinery for which the average
aggregate daily crude oil throughput for a calendar year * * * does not
exceed 75,000 barrels.'' This term is different from a small refiner,
which is what the Regulatory Flexibility Act is concerned with. A small
refiner is a small business that meets the criteria set out in SBA's
regulations at 13 CFR 121.201; whereas a small refinery, per the Energy
Policy Act, is a refinery where the annual crude throughput is less
than or equal to 75,000 barrels (i.e., a small-capacity refinery), and
could be owned by a
[[Page 55634]]
larger refiner that exceeds SBA's small entity size standards.
Previous EPA fuel regulations have afforded regulatory flexibility
provisions to small refiners, as we believe that refineries owned by
small businesses generally face unique economic challenges, compared to
larger refiners. As small refiners generally lack the resources
available to larger companies (including those larger companies that
own small-capacity refineries) to raise capital for any necessary
investments for meeting regulatory requirements, these flexibility
provisions were provided to reduce the disproportionate burden on those
refiners that qualified as small refiners.
3. Summary of Potentially Affected Small Entities
The refiners that are potentially affected by this proposed rule
are those that produce gasoline. For our recent proposed rule ``Control
of Hazardous Air Pollutants From Mobile Sources'' (71 FR 15804,
Wednesday, March 29, 2006), we performed an industry characterization
of potentially affected gasoline refiners; we used that industry
characterization to determine which refiners would also meet the SBA
definition of a small refiner under this proposal. From the industry
characterization, we determined that there were 20 gasoline refiners
that met the definition of a small refiner. Of these 20 refiners, 17
owned refineries that also met the Energy Policy Act's definition of a
small refinery.
4. Impact of the Regulations on Small Entities
As previously stated, many aspects of the RFS program, such as the
required amount of annual renewable fuel volumes, were specified in the
Energy Policy Act. As shown above in Table III.D.3.c-2, the annual
projections of ethanol production exceed the required annual renewable
fuel volumes. When the small refinery exemption ends, it is anticipated
that there will be over one billion gallons in excess RINs available.
We believe that this large volume of excess RINs will also lower the
costs of this program. If there were a shortage of RINs, or if any
party were to `hoard' RINs, the cost of a RIN could be high; however
with excess RINs, we believe that this program will not impose a
significant economic burden on small refineries, small refiners, or any
other obligated party. Further, we have determined that this proposed
rule will not have a significant economic impact on a substantial
number of small entities.
When the Agency certifies that a rule will not have a significant
economic impact on a substantial number of small entities, EPA's policy
is to make an assessment of the rule's impact on any small entities and
to engage the potentially regulated entities in a dialog regarding the
rule, and minimize the impact to the extent feasible. The following
sections discuss our outreach with the potentially affected small
entities and proposed regulatory flexibilities to decrease the burden
on these entities in compliance with the requirements of the RFS
program
5. Small Refiner Outreach
Although we do not believe that the RFS program would have a
significant economic impact on a substantial number of small entities,
EPA nonetheless has tried to reduce the impact of this rule on small
entities. We held meetings with small refiners to discuss the
requirements of the RFS program and the special provisions offered by
the Energy Policy Act for small refineries.
The Energy Policy Act set out the following provisions for small
refineries:
A temporary exemption from the Renewable Fuels Standard
requirement until 2011;
An extension of the temporary exemption period for at
least two years for any small refinery where it is determined that the
refinery would be subject to a disproportionate economic hardship if
required to comply;
Any small refinery may petition, at any time, for an
exemption based on disproportionate economic hardship; and,
A small refinery may waive its temporary exemption to
participate in the credit generation program, or it may also ``opt-
in'', by waiving its temporary exemption, to be subject to the RFS
requirement.
During these meetings with the small refiners we also discussed the
impacts of these provisions being offered to small refineries only. As
stated above, three refiners met the definition of a small refiner, but
their refineries did not meet the Act's definition of a small refinery;
which naturally concerned the small refiners. Another concern that the
small refiners had was that if this rule were to have a significant
economic impact on a substantial number of small entities a lengthy
SBREFA process would ensue (which would delay the promulgation of the
RFS rulemaking, and thus provide less lead time for these small
entities prior to the RFS program start date).
Following our discussions with the small refiners, they provided
three suggested regulatory flexibility options that they believed could
further assist affected small entities in complying with the RFS
program standard: (1) That all small refiners be afforded the Act's
small refinery temporary exemption, (2) that small refiners be allowed
to generate credits if they elect to comply with the RFS program
standard prior to the 2011 small refinery compliance date, and (3)
relieve small refiners who generate blending credits of the RFS program
compliance requirements.
We agreed with the small refiners'' suggestion that small refiners
be afforded temporary exemption that the Act specifies for small
refineries. Regarding the small refiners' second and third suggestions
regarding credits, our proposed RIN-based program will automatically
provide them with credit for any renewables that they blend into their
motor fuels. Until 2011, small refiners will essentially be treated as
oxygenate blenders and may separate RINs from batches and trade or sell
these RINs.
6. Conclusions
After considering the economic impacts of today's proposed rule on
small entities, we certify that this action will not have a significant
economic impact on a substantial number of small entities.
While the Energy Policy Act provided for a temporary exemption for
small refineries from the requirements of today's proposed rule, these
parties will have to comply with the requirements following the
exemption period. However, we still believe that small refiners
generally lack the resources available to larger companies, and
therefore find it necessary to extend the small refinery temporary
exemption to all small refiners. Thus, we are proposing to allow the
small refinery temporary exemption, as set out in the Act, to all
qualified small refiners. In addition, past fuels rulemakings have
included a provision that, to qualify for EPA's small refiner
flexibilities, a refiner must have no more than 1,500 total corporate
employees and have a crude capacity of no more than 155,000 bpcd
(slightly higher than SBA's crude capacity limit of 125,000 bpcd). To
be consistent with these previous rules, we are also proposing to allow
those refiners that meet these criteria to be considered small refiners
for this rulemaking. Lastly, we are proposing that small refiners may
separate RINs from batches and trade or sell these RINs prior to 2011
if the small refiner operates as a blender
[[Page 55635]]
We continue to be interested in the potential impacts of this
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under Section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, Section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of Section 205
do not apply when they are inconsistent with applicable law. Moreover,
Section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
Before EPA establishes any regulatory requirements that may
significantly or uniquely affect small governments, including tribal
governments, it must have developed under Section 203 of the UMRA a
small government agency plan. The plan must provide for notifying
potentially affected small governments, enabling officials of affected
small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
EPA has determined that this rule does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any one year. EPA has estimated that renewable fuel use
through 2012 will be sufficient to meet the required levels. Therefore,
individual refiners, blenders, and importers are already on track to
meet rule obligations through normal market-driven incentives. Thus,
today's rule is not subject to the requirements of Sections 202 and 205
of the UMRA.
This rule contains no Federal mandates for State, local, or tribal
governments as defined by the provisions of Title II of the UMRA. The
rule imposes no enforceable duties on any of these governmental
entities. Nothing in the rule would significantly or uniquely affect
small governments.
E. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have Federalism implications.''
``Policies that have Federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
This proposed rule does not have Federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Thus, Executive Order 13132 does
not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.''
This proposed rule does not have tribal implications, as specified
in Executive Order 13175. This rule would be implemented at the Federal
level and collectively apply to refiners, blenders, and importers. EPA
expects these entities to meet the standards on a collective basis
through 2012 even without imposition of any RFS obligations on any
individual party. Tribal governments will be affected only to the
extent they purchase and use regulated fuels. Thus, Executive Order
13175 does not apply to this rule. EPA specifically solicits additional
comment on this proposed rule from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045: ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under Section 5-501 of the Order has the
potential to influence the regulation. This proposed rule is not
subject to Executive Order 13045 because it does not establish an
environmental standard intended to mitigate health or safety risks and
because it implements specific standards established by Congress in
statutes.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355
(May 22, 2001)) because it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy.
EPA expects the provisions to have very little effect on the
national fuel supply, since normal market forces alone are promoting
greater renewable fuel use than required by the RFS mandate.
Nevertheless, the rule is an important part of the nation's efforts to
reduce dependence on foreign oil. We discuss our analysis of the energy
and supply effects of the increased use of renewable fuels in Sections
VI and X of this preamble.
[[Page 55636]]
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. The NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This proposed rulemaking does not involve technical standards.
Therefore, EPA is not considering the use of any voluntary consensus
standards.
XIII. Statutory Authority
Statutory authority for the rules proposed today can be found in
section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support
for the procedural and compliance related aspects of today's proposal,
including the proposed recordkeeping requirements, come from Sections
114, 208, and 301(a) of the CAA, 42 U.S.C. 7414, 7542, and 7601(a).
List of Subjects in 40 CFR Part 80
Environmental protection, Air pollution control, Fuel additives,
Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle
pollution, Penalties, Reporting and recordkeeping requirements.
Dated: September 7, 2006.
Stephen L. Johnson,
Administrator.
40 CFR part 80 is proposed to be amended as follows:
PART 80--REGULATION OF FUELS AND FUEL ADDITIVES
1. The authority citation for part 80 continues to read as follows:
Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a).
2. Section 80.1100 is revised to read as follows:
Sec. 80.1100 How is the statutory default requirement for 2006
implemented?
(a) Definitions. The definitions of Sec. 80.2 and the following
additional definitions apply to this section only.
(1) Renewable fuel. (i) Renewable fuel means motor vehicle fuel
that is used to replace or reduce the quantity of fossil fuel present
in a fuel mixture used to operate a motor vehicle, and which:
(A) Is produced from grain, starch, oil seeds, vegetable, animal,
or fish materials including fats, greases, and oils, sugarcane, sugar
beets, sugar components, tobacco, potatoes, or other biomass; or
(B) Is natural gas produced from a biogas source, including a
landfill, sewage waste treatment plant, feedlot, or other place where
decaying organic material is found.
(ii) The term ``renewable fuel'' includes cellulosic biomass
ethanol, waste derived ethanol, biodiesel, and any blending components
derived from renewable fuel.
(2) Cellulosic biomass ethanol means ethanol derived from any
lignocellulosic or hemicellulosic matter that is available on a
renewable or recurring basis, including dedicated energy crops and
trees, wood and wood residues, plants, grasses, agricultural residues,
fibers, animal wastes and other waste materials, and municipal solid
waste. The term also includes any ethanol produced in facilities where
animal wastes or other waste materials are digested or otherwise used
to displace 90 percent or more of the fossil fuel normally used in the
production of ethanol.
(3) Waste derived ethanol means ethanol derived from animal wastes,
including poultry fats and poultry wastes, and other waste materials,
or municipal solid waste.
(4) Small refinery means a refinery for which the average aggregate
daily crude oil throughput for a calendar year (as determined by
dividing the aggregate throughput for the calendar year by the number
of days in the calendar year) does not exceed 75,000 barrels.
(5) Biodiesel means a diesel fuel substitute produced from
nonpetroleum renewable resources that meets the registration
requirements for fuels and fuel additives established by the
Environmental Protection Agency under section 211 of the Clean Air Act.
It includes biodiesel derived from animal wastes (including poultry
fats and poultry wastes) and other waste materials, or biodiesel
derived from municipal solid waste and sludges and oils derived from
wastewater and the treatment of wastewater.
(b) Renewable fuel standard for 2006. The percentage of renewable
fuel in the total volume of gasoline sold or dispensed to consumers in
2006 in the United States shall be a minimum of 2.78 percent on an
annual average volume basis.
(c) Responsible parties. Parties collectively responsible for
attainment of the standard in paragraph (b) of this section are
refiners (including blenders) and importers of gasoline. However, a
party that is a refiner only because he owns or operates a small
refinery is exempt from this responsibility.
(d) EPA determination of attainment. EPA will determine after the
close of 2006 whether or not the requirement in paragraph (b) of this
section has been met. EPA will base this determination on information
routinely published by the Energy Information Administration on the
annual domestic volume of gasoline sold or dispensed to U.S. consumers
and of ethanol produced for use in such gasoline, supplemented by
readily available information concerning the use in motor fuel of other
renewable fuels such as cellulosic biomass ethanol, waste derived
ethanol, biodiesel, and other non-ethanol renewable fuels.
(1) The renewable fuel volume will equal the sum of all renewable
fuel volumes used in motor fuel, provided that:
(i) One gallon of cellulosic biomass ethanol or waste derived
ethanol shall be considered to be the equivalent of 2.5 gallons of
renewable fuel; and
(ii) Only the renewable fuel portion of blending components derived
from renewable fuel shall be counted towards the renewable fuel volume.
(2) If the nationwide average volume percent of renewable fuel in
gasoline in 2006 is equal to or greater than the standard in paragraph
(b) of this section, the standard has been met.
(e) Consequence of nonattainment in 2006. In the event that EPA
determines that the requirement in paragraph (b) of this section has
not been attained in 2006, a deficit carryover volume shall be added to
the renewable fuel volume obligation for 2007 for use in calculating
the standard applicable to gasoline in 2007.
(1) The deficit carryover volume shall be calculated as follows:
DC = Vgas* (Rs-Ra)
Where:
DC = Deficit carryover in gallons of renewable fuel.
Vgas = Volume of gasoline sold or dispensed to U.S. consumers in
2006, in gallons.
Rs = 0.0278.
Ra = Ratio of renewable fuel volume divided by total gasoline volume
determined in accordance with paragraph (d)(2) of this section.
(2) There shall be no other consequence of failure to attain the
standard in paragraph (b) of this section in 2006 for any of the
parties in paragraph (c) of this section.
[[Page 55637]]
3. Section 80.1101 is added to read as follows:
Sec. 80.1101 Definitions.
The definitions of Sec. 80.2 and the following additional
definitions apply for purposes of this subpart.
(a) Cellulosic biomass ethanol means either of the following:
(1) Ethanol derived from any lignocellulosic or hemicellulosic
matter that is available on a renewable or recurring basis, which
includes any of the following:
(i) Dedicated energy crops and trees.
(ii) Wood and wood residues.
(iii) Plants.
(iv) Grasses.
(v) Agricultural residues.
(vi) Animal wastes and other waste materials.
(vii) Municipal solid waste.
(2) Ethanol made at facilities at which animal wastes or other
waste materials are digested or otherwise used onsite to displace 90
percent or more of the fossil fuel that is combusted to produce thermal
energy integral to the process of making ethanol and which comply with
the recordkeeping requirements of Sec. 80.1151(a)(4).
(b) Other waste materials means either of the following:
(1) Waste materials that are residues rather than being produced
solely for the purpose of being combusted to produce energy (e.g.,
residual tops, branches, and limbs from a tree farm could be waste
materials while wood chips used as fuel and which come from plants
grown solely for such purpose would not be waste materials).
(2) Waste heat that is captured from an off-site combustion process
(e.g., furnace, boiler, heater, or chemical process).
(c) Otherwise used means either of the following:
(1) The direct combustion of the waste materials to make thermal
energy.
(2) The use of waste heat as a source of thermal energy.
(d) Waste derived ethanol means ethanol derived from either of the
following:
(1) Animal wastes, including poultry fats and poultry wastes, and
other waste materials.
(2) Municipal solid waste.
(e) Biogas means methane or other hydrocarbon gas produced from
decaying organic material, including landfills, sewage waste treatment
plants, and animal feedlots.
(f) Renewable fuel. (1) Renewable fuel is motor vehicle fuel that
is used to replace or reduce the quantity of fossil fuel present in a
fuel mixture used to operate a motor vehicle, and is produced from
either of the following:
(i) Grain.
(ii) Starch.
(iii) Oilseeds.
(iv) Vegetable, animal or fish materials including fats, greases
and oils.
(v) Sugarcane.
(vi) Sugar beets.
(vii) Sugar components.
(viii) Tobacco.
(ix) Potatoes.
(x) Other biomass; or is natural gas produced from a biogas source,
including a landfill, sewage waste treatment plant, feedlot, or other
place where decaying organic material is found.
(2) The term ``Renewable fuel'' includes cellulosic biomass
ethanol, waste derived ethanol, biodiesel (mono-alkyl ester), non-ester
renewable diesel, and blending components derived from renewable fuel.
(3) Small volume additives less than 1.0 percent of the total
volume of a renewable fuel shall be counted as part of the total
renewable fuel volume.
(4) A fuel produced by a renewable fuel producer that is used in
boilers or heaters is not a motor vehicle fuel, and therefore is not a
renewable fuel.
(g) Blending component has the same meaning as ``Gasoline blending
stock, blendstock, or component'' as defined at Sec. 80.2(s), for
which the portion that can be counted as renewable fuel is calculated
as set forth in Sec. 80.1115(a).
(h) Motor vehicle has the meaning given in Section 216(2) of the
Clean Air Act (42 U.S.C. 7550).
(i) Small refinery means a refinery for which the average aggregate
daily crude oil throughput for the calendar year 2004 (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.
(j) Biodiesel (mono-alkyl ester) means a motor vehicle fuel or fuel
additive which:
(1) Is registered as a motor vehicle fuel or fuel additive under 40
CFR part 79;
(2) Is a mono-alkyl ester;
(3) Meets ASTM D-6751-02a;
(4) Is intended for use in engines that are designed to run on
conventional diesel fuel, and
(5) Is derived from nonpetroleum renewable resources (as defined in
paragraph (o) of this section).
(k) Non-ester renewable diesel means a motor vehicle fuel or fuel
additive which:
(1) Is registered as a motor vehicle fuel or fuel additive under 40
CFR part 79;
(2) Is not a mono-alkyl ester;
(3) Is intended for use in engines that are designed to run on
conventional diesel fuel; and
(4) Is derived from nonpetroleum renewable resources (as defined in
paragraph (o) of this section).
(l) Biocrude means plant oils or animal fats that are used as
feedstocks to any production unit in a refinery that normally processes
crude oil to make gasoline or diesel fuels.
(m) Biocrude-based renewable fuels are renewable fuels that are
gasoline or diesel products resulting from the processing of biocrudes
in atmospheric distillation or other process units at refineries that
normally process petroleum-based feedstocks.
(n) Importers, for the purposes of this subpart only, are those
persons who:
(1) Are considered importers under Sec. 80.2(r); and
(2) Are persons who bring gasoline into the 48 contiguous states of
the United States from areas that have not chosen to opt in to the
program requirements of this subpart (per Sec. 80.1143).
(o) Nonpetroleum renewable resources include, but are not limited
to, either of the following:
(1) Plant oils.
(2) Animal fats and animal wastes, including poultry fats and
poultry wastes, and other waste materials.
(3) Municipal solid waste and sludges and oils derived from
wastewater and the treatment of wastewater.
(p) Export of renewable fuel means:
(1) Transfer of a batch of renewable fuel to a location outside the
United States; and
(2) Transfer of a batch of renewable fuel from the contiguous 48
states to Alaska, Hawaii, or a United States territory, unless that
state or territory has received an approval from the Administrator to
opt-in to the renewable fuel program pursuant to Sec. 80.1143.
(q) Renewable Identification Number (RIN), is a unique number
generated to represent a volume of renewable fuel in accordance with
Sec. 80.1126.
(r) Standard-value is a RIN generated to represent renewable fuel
with an equivalence value up to and including 1.0.
(s) Extra-value RIN is a RIN generated to represent renewable fuel
with an equivalence value greater than 1.0.
(t) Batch-RIN is a RIN that represents a batch of renewable fuel
containing multiple gallons. A batch-RIN uniquely identifies all of the
gallon-RINs in that batch.
(u) Gallon-RIN is a RIN that represents an individual gallon of
renewable fuel.
[[Page 55638]]
Sec. Sec. 80.1102-80.1103 [Added and Reserved]
4. Sections 80.1102 and 80.1103 are added and reserved.
5. Sections 80.1104 through 80.1107 are added to read as follows:
Sec. 80.1104 What are the implementation dates for the Renewable Fuel
Standard Program?
The RFS standards and other requirements of this subpart are
effective beginning the day after [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER.
Sec. 80.1105 What is the Renewable Fuel Standard?
(a) The annual value of the renewable fuel standard for 2007 shall
be 3.71 percent.
(b) Beginning with the 2008 compliance period, EPA will calculate
the value of the annual standard and publish this value in the Federal
Register by November 30 of the year preceding the compliance period.
(c) EPA will base the calculation of the standard on information
provided by the Energy Information Administration regarding projected
gasoline volumes and projected volumes of renewable fuel expected to be
used in gasoline blending for the upcoming year.
(d) EPA will calculate the annual renewable fuel standard using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP22SE06.006
Where:
RFStdi = Renewable Fuel Standard in year i, in percent.
RFVi = Nationwide annual volume of renewable fuels
required by section 211(o)(2)(B) of the Act (42 U.S.C. 7545) for
year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that
is projected to be used in the 48 contiguous states, in year i, in
gallons.
GSi = Amount of gasoline projected to be used in
noncontiguous states or territories (if the state or territory opts-
in) in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that
is projected to be used in noncontiguous states or territories (if
the state or territory opts-in) in year i, in gallons.
GEi = Amount of gasoline projected to be produced by
exempt small refineries and small refiners in year i, in gallons
(through 2010 only).
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).
(e) Beginning with the 2013 compliance period, EPA will calculate the
value of the annual cellulosic standard and publish this value in the
Federal Register by November 30 of the year preceding the compliance
period.
(f) EPA will calculate the annual cellulosic standard using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP22SE06.007
Where:
RFCelli = Renewable Fuel Cellulosic Standard in year i,
in percent.
Gi = Amount of gasoline projected to be used in the 48
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that
is projected to be used in the 48 contiguous states, in year i, in
gallons.
GSi = Amount of gasoline projected to be used in
noncontiguous states or territories (if the state or territory opts-
in) in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that
is projected to be used in noncontiguous states or territories (if
the state or territory opts-in) in year i, in gallons.
Celli = Amount of renewable fuel that is required to come
from cellulosic sources, in year i, in gallons (250,000,000 gallons
minimum).
Sec. 80.1106 To whom does the Renewable Volume Obligation apply?
(a)(1) An obligated party is a refiner or blender which produces
gasoline within the 48 contiguous states, or an importer which imports
gasoline into the 48 contiguous states.
(2) If the Administrator approves a petition of Alaska, Hawaii, or
a United States territory to opt-in to the renewable fuel program under
the provisions in Sec. 80.1143, then ``obligated party'' shall include
any refiner or blender which produces gasoline within that state or
territory, or an importer which imports gasoline into that state or
territory.
(b)(1) For each calendar year starting with 2007, any obligated
party is required to demonstrate, pursuant to Sec. 80.1127, that they
have satisfied the Renewable Volume Obligation for that calendar year,
as specified in Sec. 80.1107(a), except as otherwise provided in this
section.
(2) The deficit carryover provisions in Sec. 80.1127(b) only apply
if all of the requirements specified in Sec. 80.1127(b) are fully
satisfied.
(c) Any blender whose sole blending activity in a calendar year is
to blend a renewable fuel (or fuels) into gasoline, RBOB, CBOB, or
diesel fuel is not required to meet the renewable volume obligation
specified in Sec. 80.1107(a) for that gasoline for that calendar year.
Sec. 80.1107 How is the Renewable Volume Obligation calculated?
For the purposes of this section, all reformulated gasoline,
conventional gasoline and blendstock, collectively called ``gasoline''
unless otherwise specified, is subject to the requirements under this
subpart, as applicable.
(a) The Renewable Volume Obligation for an obligated party is
determined according to the following formula:
RVOi = RFStdi x GVi +
Di-1
Where:
RVOi = The Renewable Volume Obligation for a refiner,
blender, or importer for calendar year i, in gallons of renewable
fuel.
RFStdi = The renewable fuel standard for calendar year i
from Sec. 80.1105, in percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced or imported, in year i, in gallons.
Di-1 = Renewable fuel deficit carryover from the previous
year, per Sec. 80.1127(b), in gallons.
(b) The non-renewable gasoline volume for a refiner, blender, or
importer for a given year, GVi, specified in paragraph (a)
of this section is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP22SE06.008
Where:
x = Batch.
n = Total number of batches of gasoline produced or imported.
Gx = Total volume of gasoline produced or imported, per
paragraph (c) of this section, in gallons.
RBx = Total volume of renewable fuel blended into
gasoline, in gallons.
[[Page 55639]]
(c) For the purposes of this section, all of the following products
that are produced or imported during a calendar year are to be included
in the volume used to calculate a party's renewable volume obligation
under paragraph (a) of this section, except as provided in paragraph
(d) of this section:
(1) Reformulated gasoline.
(2) Conventional gasoline.
(3) Reformulated gasoline blendstock for oxygenate blending
(``RBOB'').
(4) Conventional gasoline blendstock that becomes finished
conventional gasoline upon the addition of oxygenate (``CBOB'').
(5) Gasoline treated as blendstock (``GTAB'').
(6) Blendstock that has been combined with other blendstock or
finished gasoline to produce gasoline.
(d) The following products are not included in the volume of
gasoline produced or imported used to calculate a party's renewable
volume obligation under paragraph (a) of this section:
(1) Any renewable fuel as defined in Sec. 80.1101(f).
(2) Blendstock that has not been combined with other blendstock or
finished gasoline to produce gasoline.
(3) Gasoline produced or imported for use in Alaska, Hawaii, the
Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American
Samoa, and the Commonwealth of the Northern Marianas, unless the area
has opted into the RFS program under Sec. 80.1143.
(4) Gasoline produced by a small refinery that has an exemption
under Sec. 80.1141 or an approved small refiner that has an exemption
under Sec. 80.1142 during the period that such exemptions are in
effect.
(5) Gasoline exported for use outside the United States.
(6) For blenders, the volume of finished gasoline, RBOB, or CBOB to
which a blender adds blendstocks.
(e) Compliance period. (1) For 2007, the compliance period is [DATE
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]
through December 31, 2007.
(2) Beginning in 2008, and every year thereafter, the compliance
period is January 1 through December 31.
Sec. Sec. 80.1108-80.1114 [Added and Reserved]
6. Sections 80.1108 through 80.1114 are added and reserved.
7. Section 80.1115 is added to read as follows:
Sec. 80.1115 How are equivalence values assigned by renewable fuel
producers?
(a) Each gallon of a renewable fuel shall be assigned an
equivalence value. The equivalence value is a number assigned to every
renewable fuel that is used to determine how many gallon-RINs can be
generated for a batch of renewable fuel according to Sec. 80.1126.
Equivalence Values for certain renewable fuels are assigned in
paragraph (d) of this section. For other renewable fuels, the
equivalence value shall be calculated using the following formula:
EV = (R / 0.931) * (EC / 77,550)
Where:
EV = Equivalence Value for the renewable fuel.
R = Renewable content of the renewable fuel. This is a measure of
the portion of a renewable fuel that came from a renewable source,
expressed as a percent, on an energy basis, of the renewable fuel
that comes from a renewable feedstock.
EC = Energy content of the renewable fuel, in Btu per gallon (lower
heating value).
(b) Technical justification and approval of calculation of the
Equivalence Value.
(1) Producers of renewable fuels must prepare a technical
justification of the calculation of the Equivalence Value for the
renewable fuel including a description of the renewable fuel, its
feedstock and production process.
(2) Producers shall submit the justification to the EPA for
approval.
(3) The Agency will review the technical justification and assign
an appropriate Equivalence Value to the renewable fuel based on the
procedure in paragraph (c) of this section.
(c) The equivalence value is assigned as follows:
(1) A value rounded to the nearest tenth if such value is less than
0.9.
(2) 1.0 if the calculated equivalence value is in the range of 0.9
to 1.2.
(3) 1.3, 1.5, or 1.7, for calculated values over 1.2, whichever
value is closest to the calculated equivalence value, based on the
positive difference between the calculated equivalence value and each
of these three values, except as specified in paragraphs (c)(4) and
(c)(5) of this section.
(4) 2.5 for cellulosic biomass ethanol that is produced on or
before December 31, 2012.
(5) 2.5 for waste derived ethanol.
(d) Equivalence values for some renewable fuels are as given in the
following table:
Table 1 of Sec. 80.1115.--Equivalence Values for Some Renewable Fuels
------------------------------------------------------------------------
Equivalence
Renewable fuel type value (EV)
------------------------------------------------------------------------
Cellulosic biomass ethanol and waste derived ethanol 2.5
produced on or before December 31, 2012...................
Ethanol from corn, starches, or sugar...................... 1.0
Biodiesel (mono-alkyl ester)............................... 1.5
Non-ester renewable diesel................................. 1.7
Butanol.................................................... 1.3
ETBE from corn ethanol..................................... 0.4
------------------------------------------------------------------------
Sec. Sec. 80.1116--80.1124 [Added and Reserved]
8. Sections 80.1116 through 80.1124 are added and reserved.
9. Sections 80.1125 through 80.1131 are added to read as follows:
Sec. 80.1125 Renewable Identification Numbers (RINs).
Each RIN is a 34 character numerical code of the following form:
YYYYCCCCFFFFFBBBBBRRDKSSSSSSEEEEEE
(a) YYYY is the calendar year in which the batch of renewable fuel
was produced or imported. YYYY also represents the year in which the
RIN was originally generated.
(b) CCCC is the registration number assigned according to Sec.
80.1150 to the producer or importer of the batch of renewable fuel.
(c) FFFFF is the registration number assigned according to Sec.
80.1150 to the facility at which the batch of renewable fuel was
produced or imported.
(d) BBBBB is a serial number assigned to the batch which:
(1) Is chosen by the producer or importer of the batch such that no
two batches have the same value in a given calendar year;
(2) Begins with the value 00001 for the first batch produced or
imported by a facility in a given calendar year; and
(3) Increases sequentially for subsequent batches produced or
imported by that facility in that calendar year.
(e) RR is a number representing the equivalence value of the
renewable fuel.
(1) Equivalence values are specified in Sec. 80.1115.
(2) Multiply the equivalence value by 10 to produce the value for
RR.
(f) D is a number identifying the type of renewable fuel, as
follows:
(1) D has the value of 1 if the renewable fuel can be categorized
as cellulosic biomass ethanol.
[[Page 55640]]
(2) D has the value of 2 if the renewable fuel cannot be
categorized as cellulosic biomass ethanol.
(g) K is a number identifying the type of RIN as follows:
(1) K has the value of 1 if the batch-RIN is a standard-value RIN.
(2) K has the value of 2 if the batch-RIN is an extra-value RIN.
(h) SSSSSS is a number representing the first gallon associated
with a batch of renewable fuel.
(i) EEEEEE is a number representing the last gallon associated with
a batch of renewable fuel. EEEEEE will be identical to SSSSSS in the
case of a gallon-RIN. Assign the value of EEEEEE as described in Sec.
80.1126.
Sec. 80.1126 How are RINs assigned to batches of renewable fuel by
renewable fuel producers or importers?
(a) Regional applicability. (1) Except as provided in paragraph (b)
of this section, every batch of renewable fuel produced by a facility
located in the contiguous 48 states of the United States, or imported
into the contiguous 48 states, must be assigned a RIN.
(2) If the Administrator approves a petition of Alaska, Hawaii, or
a United States territory to opt-in to the renewable fuel program under
the provisions in Sec. 80.1143, then the requirements of paragraph
(a)(1) of this section shall also apply to renewable fuel produced or
imported into that state or territory beginning in the next calendar
year.
(b) Volume threshold. Pursuant to Sec. 80.1154, producers with
renewable fuel production facilities located within the United States
that produce less than 10,000 gallons of renewable fuel each year, and
importers that import less than 10,000 gallons of renewable fuel each
year, are not required to generate and assign RINs to batches of
renewable fuel. Such producers and importers are also exempt from the
registration, reporting, and recordkeeping requirements of Sec. Sec.
80.1150 through 80.1152. However, for those producers and importers
that voluntarily generate and assign RINs, all the requirements of this
subpart apply.
(c) Generation of RINs. (1) The producer or importer of a batch of
renewable fuel must generate the RINs associated with that batch.
However, a producer of a batch of renewable fuel for export is not
required to generate a RIN for that batch if that producer is also the
exporter and exports the renewable fuel.
(2) A party generating a RIN shall specify the appropriate
numerical values for each component of the RIN in accordance with the
provisions of Sec. 80.1125 and this paragraph (c).
(3) Standard-value RINs shall be generated separately from extra-
value RINs, and distinguished from one another by the K component of
the RIN.
(4) When a standard-value batch-RIN or an extra-value batch-RIN is
initially generated by a renewable fuel producer or importer, the value
of SSSSSS in the batch-RIN shall be 000001 to represent the first
gallon in the batch of renewable fuel.
(5) Generation of standard-value batch-RINs. (i) Except as provided
in paragraph (c)(5)(ii) of this section, a standard-value batch-RIN
shall be generated to represent the gallons in a batch of renewable
fuel. The value of EEEEEE when a batch-RIN is initially generated by a
renewable fuel producer or importer shall be determined as follows:
(A) For renewable fuels with an equivalence value of 1.0 or
greater, the value of EEEEEE shall be the standardized volume of the
batch in gallons.
(B) For renewable fuels with an equivalence value of less than 1.0,
the value of EEEEEE shall be the applicable volume, in gallons,
calculated according to the following formula:
Va = EV * Vs
Where:
Va = Applicable volume of renewable fuel, in gallons, for
use in designating the value of EEEEEE.
EV = Equivalence value for the renewable fuel per Sec. 80.1115.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons.
(ii) For biocrude-based renewable fuels, a standard-value batch-RIN
shall be generated to represent the gallons of biocrude rather than the
gallons of renewable fuel. The value of EEEEEE shall be the
standardized volume of the biocrude in gallons.
(6) Generation of extra-value batch-RINs. (i) Extra-value batch-
RINs may be generated for renewable fuels having an equivalence value
greater than 1.0.
(ii) The value for EEEEEE in an extra-value batch-RIN when a batch-
RIN is initially generated by a renewable fuel producer or importer
shall be the applicable volume of renewable fuel calculated according
to the following formula:
Va = (EV-1.0) * Vs
Where:
Va = Applicable volume of renewable fuel, in gallons, for
use in designating the value of EEEEEE.
EV= Equivalence value for the renewable fuel per Sec. 80.1115.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons.
(7) Standardization of volumes. In determining the standardized
volume of a batch of renewable fuel for purposes of generating
standard-value batch-RINs or extra-value batch-RINs, pursuant to
paragraphs (c)(5) and (c)(6) of this section, the batch volumes shall
be adjusted to a standard temperature of 60 [deg]F.
(i) For ethanol, the following formula shall be used:
Vs,e = Va,e * (-0.0006301 x T + 1.0378)
Where:
Vs,e = Standardized volume of ethanol at 60 [deg]F, in
gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.
(ii) For biodiesel (mono alkyl esters), the following formula shall
be used:
Vs,b = Va,b * (-0.0008008 x T + 1.0480)
Where:
Vs,b = Standardized volume of biodiesel at 60 [deg]F, in
gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.
(iii) For other renewable fuels, an appropriate formula commonly
accepted by the industry shall be used to standardize the actual volume
to 60 [deg]F.
(d) Assignment of batch-RINs to batches. (1) The producer or
importer of a batch of renewable fuel must assign standard-value RINs
to the batch of renewable fuel that those batch-RINs represent.
(2) The producer or importer of a batch of renewable fuel may
assign extra-value batch-RINs to the batch of renewable fuel that those
batch-RINs represent.
(3) A batch-RIN is assigned to a batch when the batch-RIN is
recorded in a prominent location on a product transfer document
assigned to that batch of renewable fuel per Sec. 80.1153.
Sec. 80.1127 How are RINs used to demonstrate compliance?
(a) Renewable volume obligations. (1) Except as specified in
paragraph (b) of this section, each party that is obligated to meet the
Renewable Volume Obligation under Sec. 80.1107, or an exporter of
renewable fuels, must demonstrate that it has acquired sufficient RINs
to satisfy the following equation:
([Sigma]RINVOL)i + ([Sigma]RINVOL)i-1 =
RVOi
Where:
([Sigma]RINVOL)i = Sum of all acquired gallon-RINs that
were generated in year i and are being applied towards the
RVOi, in gallons.
([Sigma]RINVOL)i-1 = Sum of all acquired gallon-RINs that
were generated in year i-1 and are being applied towards the
RVOi, in gallons.
[[Page 55641]]
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons.
(2) For compliance for calendar years 2009 and later, the value of
([Sigma]RINVOL)i-1 may not exceed a value determined by the
following inequality:
([Sigma]RINVOL)i-1 <= 0.20 * RVOi
Where:
([Sigma]RINVOL)i-1 = Sum of all acquired gallon-RINs that
were generated in year i-1 and are being applied towards the
RVOi, in gallons.
(3) RINs may only be used to demonstrate compliance with the RVO
for the calendar year in which they were generated or the following
calendar year. RINs used to demonstrate compliance in one year cannot
be used to demonstrate compliance in any other year.
(4) A party may acquire a RIN only if that RIN is obtained in
accordance with Sec. Sec. 80.1128 and 80.1129.
(5) Gallon-RINs that can be used for compliance with the RVO shall
be calculated from the following formula:
RINVOL = EEEEEE - SSSSSS + 1
Where:
RINVOL = Gallon-RINs associated with a batch-RIN, in gallons.
EEEEEE = Batch-RIN component identifying the last gallon associated
with the batch of renewable fuel that the batch-RIN represents.
SSSSSS = Batch-RIN component identifying the first gallon associated
with the batch of renewable fuel that the batch-RIN represents.
(b) Deficit carryovers. (1) An obligated party or an exporter of
renewable fuel that fails to meet the requirements of paragraph (a)(1)
of this section for calendar year i is permitted to carry a deficit
into year i + 1 under the following conditions:
(i) The party did not carry a deficit into calendar year i from
calendar year i-1.
(ii) The party subsequently meets the requirements of paragraph
(a)(1) of this section for calendar year i+1.
(2) A deficit is calculated according to the following formula:
Di = RVOi - [([Sigma]RINVOL)i +
([Sigma]RINVOL)i-1]
Where:
Di = The deficit generated in calendar year i that must
be carried over to year i+1 if allowed pursuant to paragraph
(b)(1)(i) of this section, in gallons.
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons.
([Sigma]RINVOL)1 = Sum of all acquired gallon-RINs that
were generated in year i and are being applied towards the
RVOi, in gallons.
([Sigma]RINVOL)i-1 = Sum of all acquired
gallon-RINs that were generated in year i-1 and are being applied
towards the RVOi, in gallons.
Sec. 80.1128 General requirements for RIN distribution.
(a) RINs assigned to batches of renewable fuel. (1) Except as
provided in Sec. 80.1129 and paragraph (a)(3) of this section, as
title to a batch of renewable fuel is transferred from one party to
another, a batch-RIN that has been assigned to that batch according to
Sec. 80.1126(d) must remain assigned to an equivalent renewable fuel
volume having the same equivalence value.
(i) A batch-RIN assigned to a batch shall be identified on product
transfer documents representing the batch pursuant to Sec. 80.1153.
(ii) Any documentation used to transfer custody of or title to a
batch from one party to another must identify the batch-RINs assigned
to that batch.
(2) If two or more batches of renewable fuel are combined into a
single batch, then all the batch-RINs assigned to all the batches
involved in the merger shall be assigned to the final combined batch.
(3) If a batch of renewable fuel is split into two or more smaller
batches, any batch-RINs assigned to the parent batch must likewise be
split and assigned to the daughter batches.
(i) If the Equivalence Value for the renewable fuel in the parent
batch is equal to or greater than 1.0, then there shall be at least one
gallon-RIN for every gallon in each of the daughter batches.
(ii) If the Equivalence Value for the renewable fuel in the parent
batch is less than 1.0, then the ratio of gallon-RINs to gallons in the
parent batch shall be preserved in all daughter batches.
(iii) For purposes of this paragraph (a)(3), the volume of each
parent and daughter batch shall be standardized to 60 [deg]F pursuant
to Sec. 80.1126(c)(7).
(b) RINs not assigned to batches of renewable fuel. (1) Unassigned
RIN means one of the following:
(i) It is a RIN that contains a K value identifying it as an extra-
value RIN and was not assigned to a batch of renewable fuel by the
producer or importer of that batch; or
(ii) It is a RIN that was separated from the batch to which it was
assigned in accordance with Sec. 80.1129.
(2) Any party that has registered pursuant to Sec. 80.1150 can
hold title to an unassigned RIN.
(3) Unassigned RINs can be transferred from one party to another
any number of times.
(4) An unassigned batch-RIN can be divided by its holder into two
batch-RINs, each representing a smaller number of gallon-RINs if all of
the following conditions are met:
(i) All RIN components other than SSSSSS and EEEEEE are identical
for the parent and daughter RINs.
(ii) The sum of the gallon-RINs associated with the two daughter
batch-RINs is equal to the gallon-RINs associated with the parent
batch.
Sec. 80.1129 Requirements for separating RINs from batches.
(a)(1) Separation of a RIN from a batch means termination of the
assignment of the RIN from a batch of renewable fuel.
(2) A RIN that has been assigned to a batch of renewable fuel
according to Sec. 80.1126(d) may be separated from a batch only under
one of the following conditions:
(i) A party that is an obligated party according to Sec. 80.1106
may separate any RINs that have been assigned to a batch if they own
the batch.
(ii) Except as provided in paragraph (a)(2)(v) of this section, any
party that owns a batch of renewable fuel shall have the right to
separate any RINs that have been assigned to that batch once the batch
is blended with gasoline or diesel to produce a motor vehicle fuel.
(iii) Any party that exports a batch of renewable fuel shall have
the right to separate any RINs that have been assigned to the exported
batch.
(iv) Except as provided in paragraph (a)(2)(v) of this section, any
renewable fuel producer that owns a batch of renewable fuel shall have
the right to separate any RINs that have been assigned to that batch if
the renewable fuel is designated as motor vehicle fuel in its neat form
and is used as motor vehicle fuel in its neat form.
(v) RINs assigned to batches of biodiesel (mono-alkyl esters) can
only be separated from those batches once the biodiesel is blended into
diesel fuel at a concentration of 80 volume percent biodiesel or less.
(b) Upon separation from its associated batch, a RIN shall be
removed from all documentation that:
(1) Is used to identify custody or title to the batch; or
(2) Is transferred with the batch.
(c) RINs that have been separated from batches of renewable fuel
become unassigned RINs subject to the provisions of Sec. 80.1128(b).
Sec. 80.1130 Requirements for exporters of renewable fuels.
(a)(1) Any party that exports any amount of renewable fuel shall
acquire sufficient RINs to offset a Renewable Volume Obligation
representing the exported renewable fuel.
[[Page 55642]]
(2) Only exporters located in the applicable region described in
Sec. 80.1126(a) are subject to the requirements of this section.
(b) Renewable Volume Obligations. An exporter of renewable fuel
shall determine its Renewable Volume Obligation from the volumes of the
batches exported.
(1) A renewable fuel exporter's total Renewable Volume Obligation
shall be calculated according to the following formula:
RVOi = [Sigma](VOLk * EVk) +
Di-1
Where:
k = Batch.
RVOi = The Renewable Volume Obligation for the exporter
for calendar year i, in gallons of renewable fuel.
VOLk = The standardized volume of batch k of exported
renewable fuel, in gallons.
EVk = The equivalence value for batch k.
Di-1 = Renewable fuel deficit carryover from
the previous year, in gallons.
(2)(i) For exported batches of renewable fuel that have assigned
RINs, the equivalence value may be determined from the RR component of
the RIN.
(ii) If a batch of renewable fuel does not have assigned RINs but
its equivalence value may nevertheless be determined pursuant to Sec.
80.1115(d) based on its composition, then the appropriate equivalence
value shall be used in the calculation of the exporter's Renewable
Volume Obligation.
(iii) If the equivalence value for a batch of renewable fuel cannot
be determined, the value of EVk shall be 1.0.
(3) If the exporter of a batch of renewable fuel is also the
producer of that batch, and no RIN was generated to represent that
batch, then the volume of that batch shall be excluded from the
calculation of the Renewable Volume Obligation.
(c) Each exporter of renewable fuel must demonstrate compliance
with its RVO using RINs it has acquired pursuant to Sec. 80.1127.
Sec. 80.1131 Treatment of invalid RINs.
(a) Invalid RINs. An invalid RIN is a RIN that:
(1) Is a duplicate of a valid RIN;
(2) Was based on volumes that have not been standardized to 60
[deg]F;
(3) Has expired;
(4) Was based on an incorrect equivalence value; or
(5) Was otherwise improperly generated.
(b) In the case of RINs that have been determined to be invalid,
the following provisions apply:
(1) Invalid RINs cannot be used to achieve compliance with the
transferee's Renewable Volume Obligation, regardless of the
transferee's good faith belief that the RINs were valid.
(2) The refiner or importer who used the invalid RINs, and any
transferor of the invalid RINs, must adjust their records, reports, and
compliance calculations as necessary to reflect the deletion of invalid
RINs.
(3) Any valid RINs remaining after deleting invalid RINs, and after
an obligated party applies valid RINs as needed to meet the RVO at the
end of the compliance year, must first be applied to correct the
invalid transfers before the transferor trades or banks the RINs.
(4) In the event that the same RIN is transferred to two or more
parties, the RIN will be deemed to be invalid, and any party to any
transfer of the invalid RIN will be deemed liable for any violations
arising from the transfer or use of the invalid RIN.
(5) A RIN will not be deemed invalid where it can be determined
that the RIN was properly created and transferred.
Sec. Sec. 80.1132-80.1140 [Added and Reserved]
10. Sections 80.1132 through 80.1140 are added and reserved.
11. Sections 80.1141 through 80.1143 are added to read as follows:
Sec. 80.1141 Small refinery exemption.
(a)(1) Pursuant to Sec. 80.1107(d), gasoline produced by a refiner
at a small refinery is qualified for an exemption from the renewable
fuels standards of Sec. 80.1105 if that refinery meets the definition
of a small refinery under Sec. 80.1101(i) for calendar year 2004.
(2) This exemption shall apply through December 31, 2010, unless a
refiner chooses to opt-in to the program requirements of this subpart
(per paragraph (g) of this section) prior to this date.
(b)(1) To apply for an exemption under this section, a refiner must
submit an application to EPA containing the following information:
(i) The annual average aggregate daily crude oil throughput for the
period January 1, 2004, through December 31, 2004 (as determined by
dividing the aggregate throughput for the calendar year by the number
365);
(ii) A letter signed by the president, chief operating or chief
executive officer of the company, or his/her designee, stating that the
information contained in the application is true to the best of his/her
knowledge, and that the company owned the refinery as of January 1,
2006; and
(iii) Name, address, phone number, facsimile number, and E-mail
address of a corporate contact person.
(2) Applications must be submitted by September 1, 2007.
(c) Within 60 days of EPA's receipt of a refiner's application for
a small refinery exemption, EPA will notify the refiner if the
exemption is not approved or of any deficiencies in the application. In
the absence of such notification from EPA, the effective date of the
small refinery exemption is 60 days from EPA's receipt of the refiner's
submission.
(d) If EPA finds that a refiner provided false or inaccurate
information on its application for a small refinery exemption, the
exemption will be void ab initio upon notice from EPA.
(e) If a refiner is complying on an aggregate basis for multiple
refineries, any such refiner may exclude from the calculation of its
Renewable Volume Obligation (under Sec. 80.1107(a)) gasoline from any
refinery receiving the small refinery exemption under paragraph (a) of
this section.
(f)(1) The exemption period in paragraph (a) of this section shall
be extended by the Administrator for a period of not less than two
additional years if a study by the Secretary of Energy determines that
compliance with the requirements of this subpart would impose a
disproportionate economic hardship on the small refinery.
(2) A refiner may at any time petition the Administrator for an
extension of its small refinery exemption under paragraph (a) of this
section for the reason of disproportionate economic hardship.
(3) A petition for an extension of the small refinery exemption
must specify the factors that demonstrate a disproportionate economic
hardship and must provide a detailed discussion regarding the inability
of the refinery to produce gasoline meeting the requirements of Sec.
80.1105 and the date the refiner anticipates that compliance with the
requirements can be achieved at the small refinery.
(4) The Administrator shall act on such a petition not later than
90 days after the date of receipt of the petition.
(g) At any time, a refiner with an approved small refinery
exemption under paragraph (a) of this section may waive that exemption
upon notification to EPA.
(1) A refiner's notice to EPA that it intends to waive its small
refinery exemption must be received by November 1.
(2) The waiver will be effective beginning on January 1 of the
following calendar year, at which point the gasoline produced at that
refinery will be subject to the renewable fuels standard of Sec.
80.1105.
[[Page 55643]]
(3) The waiver must be sent to EPA at one of the addresses listed
in paragraph (m) of this section.
(h) A refiner that acquires a refinery from either an approved
small refiner (under Sec. 80.1142) or another refiner with an approved
small refinery exemption under paragraph (a) of this section shall
notify EPA in writing no later than 20 days following the acquisition.
(i) Applications under paragraph (b) of this section, petitions for
hardship extensions under paragraph (f) of this section, and small
refinery exemption waivers under paragraph (g) of this section shall be
sent to one of the following addresses:
(1) For U.S. mail: U.S. EPA--Attn: RFS Program, Transportation and
Regional Programs Division (6406J), 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460; or
(2) For overnight or courier services: U.S. EPA, Attn: RFS Program,
Transportation and Regional Programs Division (6406J), 1310 L Street,
NW., 6th floor, Washington, DC 20005.
Sec. 80.1142 What are the provisions for small refiners under the RFS
program?
(a)(1) A refiner qualifies for a small refiner exemption if the
refiner does not meet the definition of a small refinery under Sec.
80.1101(i) but meets all of the following criteria:
(i) The refiner produced gasoline at the refinery by processing
crude oil through refinery processing units from January 1, 2004
through December 31, 2004.
(ii) The refiner employed an average of no more than 1,500 people,
based on the average number of employees for all pay periods for
calendar year 2004 for all subsidiary companies, all parent companies,
all subsidiaries of the parent companies, and all joint venture
partners.
(iii) The refiner had a corporate-average crude oil capacity less
than or equal to 155,000 barrels per calendar day (bpcd) for 2004.
(2) The small refiner exemption shall apply through December 31,
2010, unless a refiner chooses to opt-in to the program requirements of
this subpart (per paragraph (g) of this section) prior to this date.
(b) To apply for an exemption under this section, a refiner must
submit an application to EPA containing all of the following
information for the refiner and for all subsidiary companies, all
parent companies, all subsidiaries of the parent companies, and all
joint venture partners; approval of an exemption application will be
based on all information submitted under this paragraph and any other
relevant information:
(1) (i) A listing of the name and address of each company location
where any employee worked for the period January 1, 2004 through
December 31, 2004.
(ii) The average number of employees at each location based on the
number of employees for each pay period for the period January 1, 2004
through December 31, 2004.
(iii) The type of business activities carried out at each location.
(iv) For joint ventures, the total number of employees includes the
combined employee count of all corporate entities in the venture.
(v) For government-owned refiners, the total employee count
includes all government employees.
(2) The total corporate crude oil capacity of each refinery as
reported to the Energy Information Administration (EIA) of the U.S.
Department of Energy (DOE), for the period January 1, 2004 through
December 31, 2004. The information submitted to EIA is presumed to be
correct. In cases where a company disagrees with this information, the
company may petition EPA with appropriate data to correct the record
when the company submits its application.
(3) A letter signed by the president, chief operating or chief
executive officer of the company, or his/her designee, stating that the
information contained in the application is true to the best of his/her
knowledge, and that the company owned the refinery as of January 1,
2006.
(4) Name, address, phone number, facsimile number, and e-mail
address of a corporate contact person.
(c) Applications under paragraph (b) of this section must be
submitted by September 1, 2007. EPA will notify a refiner of approval
or disapproval of its small refiner status in writing.
(d) A refiner who qualifies as a small refiner under this section
and subsequently fails to meet all of the qualifying criteria as set
out in paragraph (a) of this section will have its small refiner
exemption terminated effective January 1 of the next calendar year;
however, disqualification shall not apply in the case of a merger
between two approved small refiners.
(e) If EPA finds that a refiner provided false or inaccurate
information on its application for small refiner status under this
subpart, the small refiner's exemption will be void ab initio upon
notice from EPA.
(f) If a small refiner is complying on an aggregate basis for
multiple refineries, the refiner may exclude those refineries from the
compliance calculations under Sec. 80.1125.
(g) (1) An approved small refiner may, at any time, waive the
exemption under paragraph (a) of this section upon notification to EPA.
(2) An approved small refiner's notice to EPA that it intends to
waive the exemption under paragraph (a) of this section must be
received by November 1 in order for the waiver to be effective for the
following calendar year. The waiver will be effective beginning on
January 1 of the following calendar year, at which point the refiner
will be subject to the renewable fuels standard of Sec. 80.1105.
(3) The waiver must be sent to EPA at one of the addresses listed
in paragraph (i) of this section.
(h) A refiner that acquires a refinery from another refiner with
approved small refiner status under paragraph (a) of this section shall
notify EPA in writing no later than 20 days following the acquisition.
(i) Applications under paragraph (b) of this section shall be sent
to one of the following addresses:
(1) For U.S. Mail: U.S. EPA--Attn: RFS Program, Transportation and
Regional Programs Division (6406J), 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460; or
(2) For overnight or courier services: U.S. EPA, Attn: RFS Program,
Transportation and Regional Programs Division (6406J), 1310 L Street,
NW., 6th floor, Washington, DC 20005.
Sec. 80.1143 What are the opt-in provisions for noncontiguous states
and territories?
(a) A noncontiguous state or United States territory may petition
the Administrator to opt-in to the program requirements of this
subpart.
(b) The petition must be signed by the Governor of the state or his
authorized representative (or the equivalent official of the
territory).
(c) The Administrator will approve the petition if it meets the
provisions of paragraphs (b) and (d) of this section.
(d)(1) A petition submitted under this section must be received by
the Agency by October 31 for the state or territory to be included in
the RFS program in the next calendar year.
(2) A petition submitted under this section should be sent to one
of the following addresses:
(i) For U.S. Mail: U.S. EPA-Attn: RFS Program, Transportation and
Regional Programs Division (6406J), 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460; or
(ii) For overnight or courier services: U.S. EPA, Attn: RFS
Program, Transportation and Regional Programs
[[Page 55644]]
Division (6406J), 1310 L Street, NW., 6th floor, Washington, DC 20005.
(e) Upon approval of the petition by the Administrator--
(1) EPA shall calculate the standard for the following year,
including the total gasoline volume for the state or territory in
question.
(2) Beginning on January 1 of the next calendar year, all gasoline
producers in the state or territory for which a petition has been
approved shall be obligated parties as defined in Sec. 80.1106.
(3) Beginning on January 1 of the next calendar year, all renewable
fuel producers in the State or territory for which a petition has been
approved shall, pursuant to Sec. 80.1126(a)(2), be required to
generate RINs and assign them to batches of renewable fuel.
Sec. Sec. 80.1144-80.1149 [Added and Reserved]
12. Sections 80.1144 through 80.1149 are added and reserved.
13. Sections 80.1150 through 80.1154 are added to read as follows:
Sec. 80.1150 What are the registration requirements under the RFS
program?
(a)(1) Any obligated party as defined in Sec. 80.1106 and any
exporter of renewable fuel that is subject to a renewable fuels
standard under this subpart, as of [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER], must provide EPA with the
information specified for registration under Sec. 80.76, if such
information has not already been provided under the provisions of this
part. In addition, for each import facility, the same identifying
information as required for each refinery under Sec. 80.76(c) must be
provided. Registrations must be submitted by no later than [DATE 90
DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].
(2) Any obligated party, as defined in Sec. 80.1106, or any
exporter of renewable fuel that becomes subject to a renewable fuels
standard under this subpart after the date specified in paragraph
(a)(1) of this section, must provide EPA the information specified for
registration under Sec. 80.76, if such information has not already
been provided under the provisions of this part, and must receive EPA-
issued company and facility identification numbers prior to engaging in
any transaction involving RINs. Additionally, for each import facility,
the same identifying information as required for each refinery under
Sec. 80.76(c) must be provided.
(b)(1) Any producer of a renewable fuel that is subject to a
renewable fuels standard under this subpart as of [DATE 60 DAYS AFTER
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], must provide
EPA the information specified under Sec. 80.76, if such information
has not already been provided under the provisions of this part, by no
later than [DATE 90 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER] .
(2) Any producer of renewable fuel that becomes subject to a
renewable fuels standard under this subpart after the date specified in
paragraph (b)(1) of this section, must provide EPA the information
specified for registration under Sec. 80.76, if such information has
not already been provided under the provisions of this part, and must
receive EPA-issued company and facility identification numbers prior to
generating or creating any RINs.
(c) Any party not covered by paragraphs (a) and (b) of this section
must provide EPA the information specified under Sec. 80.76, if such
information has not already been provided under the provisions of this
part, and must receive EPA-issued company and facility identification
numbers prior to owning any RINs.
(d) Registration shall be on forms, and following policies,
established by the Administrator.
Sec. 80.1151 What are the recordkeeping requirements under the RFS
program?
(a) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any obligated party as defined under
Sec. 80.1106 or exporter of renewable fuel that is subject to the
renewable fuels standard under Sec. 80.1105 must keep all the
following records:
(1) The applicable product transfer documents under Sec. 80.1153.
(2) Copies of all reports submitted to EPA under Sec. 80.1152(a).
(3) Records related to each transaction involving the sale,
purchase, brokering, and trading of RINs, which includes all the
following:
(i) A list of the RINs owned or transferred.
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The location, time, and date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(4) Records related to the use of RINs, by facility, for
compliance, which includes all the following:
(i) Methods and variables used to calculate the Renewable Volume
Obligation pursuant to Sec. 80.1107.
(ii) List of RINs surrendered to EPA used to demonstrate
compliance.
(iii) Additional information related to details of RIN use for
compliance.
(5) Verifiable records of all the following:
(i) The amount and type of fossil fuel and waste material-derived
fuel used in producing on-site thermal energy dedicated to the
production of ethanol at plants producing cellulosic ethanol as defined
in Sec. 80.1101(a)(2).
(ii) The equivalent amount of fossil fuel (based on reasonable
estimates) associated with the use of off-site generated waste heat
that is used in the production of ethanol at plants producing
cellulosic ethanol as defined in Sec. 80.1101(a)(2).
(b) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any importer or producer of renewable
fuel as defined under Sec. 80.1101(e) must keep all the following
records:
(1) The applicable product transfer documents under Sec. 80.1153.
(2) Copies of all reports submitted to EPA under Sec. 80.1152(b).
(3) Records related to the generation of RINs, for each facility,
including all of the following:
(i) Batch Volume.
(ii) RIN number as assigned under Sec. 80.1126.
(iii) Identification of those batches meeting the definition of
cellulosic biomass ethanol.
(iv) Date of production or import.
(v) Results of any laboratory analysis of batch chemical
composition or physical properties.
(vi) Additional information related to details of RIN generation.
(4) Records related to each transaction involving the sale,
purchase, brokering, and trading of RINs, including all of the
following:
(i) A list of the RINs acquired, owned or transferred.
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The location, time, and date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(c) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any party, other than those parties
covered in paragraphs (a) and (b) of this section, that owns RINs must
keep all of the following records:
(1) The applicable product transfer documents under Sec. 80.1153.
(2) Copies of all reports submitted to EPA under Sec. 80.1152(c).
(3) Records related to each transaction involving the sale,
purchase, brokering, and trading of RINs, including all of the
following:
(i) A list of the RINs acquired, owned, or transferred.
[[Page 55645]]
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The location, time, and date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(d) The records required under this section and under Sec. 80.1153
shall be kept for five years from the date they were created, except
that records related to transactions involving RINs shall be kept for
five years from the date of transfer.
(e) On request by EPA, the records required under this section and
under Sec. 80.1153 must be made available to the Administrator or the
Administrator's authorized representative. For records that are
electronically generated or maintained, the equipment or software
necessary to read the records shall be made available; or, if requested
by EPA, electronic records shall be converted to paper documents which
shall be provided to the Administrator's authorized representative.
Sec. 80.1152 What are the reporting requirements under the RFS
program?
(a) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any obligated party as defined in Sec.
80.1106 or exporter of renewable fuel that is subject to the renewable
fuels standard under Sec. 80.1105, and continuing for each year
thereafter, must submit to EPA annual reports that contain the
information required in this section and such other information as EPA
may require:
(1) A summary report of the annual gasoline volume produced or
imported, or volume of renewable fuel exported, and whether the party
is complying on a corporate (aggregate) or facility-by-facility basis.
This report shall include all of the following:
(i) The obligated party's name.
(ii) The EPA company registration number.
(iii) The EPA facility registration number(s).
(iv) The production volume of finished gasoline, RBOB as defined in
Sec. 80.1107(c) and CBOB as defined in Sec. 80.1107(c).
(v) The renewable volume obligation (RVO), as defined in Sec.
80.1127(a) for obligated parties and Sec. 80.1130 for exporters of
renewable fuel, for the reporting year.
(vi) Any deficit RVO carried over from the previous year.
(vii) Any deficit RVO carried into the subsequent year.
(viii) The total number of RINs used for compliance.
(ix) A list of all RINs used for compliance.
(x) Any additional information that the Administrator may require.
(2) A report documenting each transaction of RINs traded between
two parties, shall include all of the following:
(i) The submitting party's name.
(ii) The submitter's EPA company registration number.
(iii) The submitter's EPA facility registration number(s).
(iv) The compliance period,
(v) Transaction type (e.g. purchase, sale).
(vi) Transaction date.
(vii) Trading partner's name.
(viii) Trading partner's EPA company registration number.
(ix) Trading partner's EPA facility registration number.
(x) RINs traded.
(xi) Any additional information that the Administrator may require.
(3) A report that summarizes RIN activities for a given compliance
year shall include all of the following information:
(i) The total prior-years RINs carried over into the current year
(on an annual basis beginning January 1).
(ii) The total current-year RINS acquired.
(iii) The total prior-years RINs acquired.
(iv) The total current-year RINs sold.
(v) The total prior-years RINs sold.
(vi) The total current-year RINs used.
(vii) The total prior-years RINs used.
(viii) The total current-year RINs expired.
(ix) The total prior-years RINs expired.
(x) The total current-year RINs to be carried into next year.
(xi) Any additional information that the Administrator may require.
(4) Reports shall be submitted on forms and following procedures as
prescribed by EPA.
(5) Reports shall be submitted by February 28 for the previous
compliance year.
(6) All reports must be signed and certified as meeting all the
applicable requirements of this subpart by the owner or a responsible
corporate officer of the obligated party.
(b) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any producer or importer of a renewable
fuel that is subject to the renewable fuels standard under Sec.
80.1105, and continuing for each year thereafter, must submit to EPA
annual reports that contain all of the following information:
(1) An annual report that includes all of the following information
on a per-batch basis, where ``batch'' means a discreet quantity of
renewable fuel produced and assigned a unique RIN:
(i) The renewable fuel producer's name.
(ii) The EPA company registration number.
(iii) The EPA facility registration number(s).
(iv) The 34 character RINs generated for each batch according to
Sec. 80.1126.
(v) The production date of each batch.
(vi) The renewable fuel type as defined in Sec. 80.1101(f).
(vii) Information related to the volume of denaturant and
applicable equivalence value.
(viii) The volume produced.
(ix) Any additional information the Administrator may require.
(2) A report documenting each transaction of RINs traded between
two parties, shall include all of the following information:
(i) The submitting party's name.
(ii) The submitter's EPA company registration number.
(iii) The submitter's EPA facility registration number(s).
(iv) The compliance period.
(v) Transaction type (e.g. purchase, sale).
(vi) Transaction date.
(vii) Trading partner's name.
(viii) Trading partner's EPA company registration number.
(ix) Trading partner's EPA facility registration number;
(x) RINs traded.
(xi) Any additional information the Administrator may require.
(3) A report that summarizes RIN activities for a compliance year
shall include all of the following information:
(i) The total prior-years RINs carried over into the current year
(on an annual basis beginning January 1).
(ii) The total current-year RINs generated.
(iii) The total current-year RINS acquired.
(iv) The total prior-years RINs acquired.
(v) The total current-years RINs sold.
(vi) The total prior-years RINs sold.
(vii) The total current-years RINs expired.
(viii) The total prior-years RINs expired.
(ix) The total current-year RINs to be carried into next year.
(x) Any additional information the Administrator may require.
(4) Reports shall be submitted on forms and following procedures as
prescribed by EPA.
(5) Reports shall be submitted by February 28 for the previous
year.
(6) All reports must be signed and certified as meeting all the
applicable
[[Page 55646]]
requirements of this subpart by the owner or a responsible corporate
officer of the renewable fuel producer.
(c) Any party, other than those parties covered in paragraphs (a)
and (b) of this section, who owns RINs must submit to EPA annual
reports that contain all of the following information:
(1) A report documenting each transaction of RINs traded between
two parties shall include all of the following:
(i) The submitting party's name.
(ii) The submitter's EPA company registration number.
(iii) The submitter's EPA facility registration number(s).
(iv) The compliance period.
(v) Transaction type (e.g. purchase, sale).
(vi) Transaction date.
(vii) Trading partner's name.
(viii) Trading partner's EPA company registration number.
(ix) Trading partner's EPA facility registration number.
(x) RINs traded.
(xi) Any additional information the Administrator may require.
(2) A report that summarizes RIN activities for a compliance year
shall include all of the following information:
(i) The total prior-years RINs carried over into the current year
(on an annual basis beginning January 1).
(ii) The total current-year RINS acquired.
(iii) The total prior-years RINs acquired.
(iv) The total current-years RINs sold.
(v) The total prior-years RINs sold.
(vi) The total current-years RINs expired.
(vii) The total prior-years RINs expired.
(viii) The total current-year RINs to be carried into next year.
(ix) Any additional information the Administrator may require.
(3) Reports shall be submitted on forms and following procedures as
prescribed by EPA.
(4) Reports shall be submitted by February 28 for the previous
year.
(5) All reports must be signed and certified as meeting all the
applicable requirements of this subpart by the owner or a responsible
corporate officer of the renewable fuel producer.
Sec. 80.1153 What are the product transfer document (PTD)
requirements for the RFS program?
(a) Any time that a person transfers ownership of renewable fuels
subject to this subpart, and when RINs continue to accompany the
renewable fuel, the transferor must provide to the transferee documents
identifying the renewable fuel and assigned RINs which include all of
the following information as applicable:
(1) The name and address of the transferor and transferee.
(2) The transferor's and transferee's EPA company registration
number.
(3) The transferor's and transferee's EPA facility registration
number.
(4) The volume of renewable fuel that is being transferred.
(5) The location of the renewable fuel at the time of transfer.
(6) The date of the transfer.
(7) The RINs assigned to the volume of renewable fuel that is being
transferred.
(b) Except for transfers to truck carriers, retailers or wholesale
purchaser-consumers, product codes may be used to convey the
information required under paragraphs (a)(1) through (a)(4) of this
section if such codes are clearly understood by each transferee. The
RIN number required under paragraph (a)(7) of this section must always
appear in its entirety.
Sec. 80.1154 What are the provisions for renewable fuel producers and
importers who produce or import less than 10,000 gallons of renewable
fuel per year?
(a) Renewable fuel production facilities located within the United
States that produce less than 10,000 gallons of renewable fuel each
year, and importers who import less than 10,000 gallons of renewable
fuel each year, are not required to generate RINs or to assign RINs to
batches of renewable fuel. Such producers and importers that do not
generate and/or assign RINs to batches of renewable fuel are exempt
from the following requirements of subpart K, except as stated in
paragraph (b) of this section:
(1) The registration requirements of Sec. 80.1150:
(2) The recordkeeping requirements of Sec. 80.1151; and
(3) The reporting requirements of Sec. 80.1152.
(b) Renewable fuel producers and importers who produce or import
less than 10,000 gallons of renewable fuel each year and that generate
and/or assign RINs to batches of renewable fuel are subject to the
provisions of Sec. Sec. 80.1150 through 80.1152.
Sec. Sec. 80.1155-80.1159 [Added and Reserved]
14. Sections 80.1155 through 80.1159 are added and reserved.
15. Sections 80.1160 through 80.1165 are added to read as follows:
Sec. 80.1160 What acts are prohibited under the RFS program?
(a) Renewable fuels producer or importer violation. Except as
provided in Sec. 80.1154, no person shall produce or import a
renewable fuel that is not assigned the proper RIN value or identified
by a RIN number as required under Sec. 80.1126.
(b) RIN generation and transfer violations. No person shall do any
of the following:
(1) Improperly generate a RIN (i.e., generate a RIN for which the
applicable renewable fuel volume was not produced).
(2) Transfer to any person an invalid RIN or a RIN that is not
properly identified as required under Sec. 80.1125.
(c) RIN use violations. No person shall do any of the following:
(1) Fail to acquire sufficient RINs, or use invalid RINs, to meet
the party's renewable fuel obligation under Sec. 80.1127.
(2) Fail to acquire sufficient RINs to meet the party's renewable
fuel obligation under Sec. 80.1130.
(d) Causing a violation. No person shall cause another person to
commit an act in violation of any prohibited act under this section.
Sec. 80.1161 Who is liable for violations under the RFS program?
(a) Persons liable for violations of prohibited acts. (1) Any
person who violates a prohibition under Sec. 80.1160(a) through (c) is
liable for the violation of that prohibition.
(2) Any person who causes another person to violate a prohibition
under Sec. 80.1160(a) through (c) is liable for a violation of Sec.
80.1160(d).
(b) Persons liable for failure to meet other provisions of this
subpart.(1) Any person who fails to meet a requirement of any provision
of this subpart is liable for a violation of that provision.
(2) Any person who causes another person to fail to meet a
requirement of any provision of this subpart is liable for causing a
violation of that provision.
(c) Parent corporation liability. Any parent corporation is liable
for any violation of this subpart that is committed by any of its
subsidiaries.
(d) Joint venture liability. Each partner to a joint venture is
jointly and severally liable for any violation of this subpart that is
committed by the joint venture operation.
Sec. 80.1162 [Reserved]
Sec. 80.1163 What penalties apply under the RFS program?
(a) Any person who is liable for a violation under Sec. 80.1161 is
subject a to civil penalty of up to $32,500, as specified in sections
205 and 211(d) of the Clean Air Act, for every day of each such
violation and the amount of economic benefit or savings resulting from
each violation.
[[Page 55647]]
(b) Any person liable under Sec. 80.1161(a) for a violation of
Sec. 80.1160(c) for failure to meet a renewable fuels obligation or
causing another party to fail to meet a renewable fuels obligation
during any averaging period, is subject to a separate day of violation
for each day in the averaging period.
(c) Any person liable under Sec. 80.1161(b) for failure to meet,
or causing a failure to meet, a requirement of any provision of this
subpart is liable for a separate day of violation for each day such a
requirement remains unfulfilled.
Sec. 80.1164 What are the attest engagement requirements under the
RFS program?
In addition to the requirements for attest engagements under
Sec. Sec. 80.125 through 80.133, and other applicable attest
engagement provisions, the following annual attest engagement
procedures are required under this subpart.
(a) The following attest procedures shall be completed for any
obligated party as stated in Sec. 80.1106(b) or exporter of renewable
fuel that is subject to the renewable fuel standard under Sec.
80.1105:
(1) Annual summary report. (i) Obtain and read a copy of the annual
summary report required under Sec. 80.1152(a)(1) which contains
information regarding:
(A) The obligated party's volume of finished gasoline, reformulated
gasoline blendstock for oxygenate blending (RBOB), and conventional
gasoline blendstock that becomes finished conventional gasoline upon
the addition of oxygenate (CBOB) produced or imported during the
reporting year;
(B) Renewable volume obligation (RVO); and
(C) RINs used for compliance.
(ii) Obtain documentation of any volumes of renewable fuel used in
gasoline during the reporting year; compute and report as a finding the
volumes of renewable fuel represented in these documents.
(iii) Agree the volumes of gasoline reported to EPA in the report
required under Sec. 80.1152(a)(1) with the volumes, excluding any
renewable fuel volumes, contained in the inventory reconciliation
analysis under Sec. 80.133.
(iv) Verify that the production volume information in the obligated
party's annual summary report required under Sec. 80.1152(a)(1) agrees
with the volume information, excluding any renewable fuel volumes,
contained in the inventory reconciliation analysis under Sec. 80.133.
(v) Compute and report as a finding the obligated party's RVO, and
any deficit RVO carried over from the previous year or carried into the
subsequent year, and verify that the values agree with the values
reported to EPA.
(vi) Obtain documentation for all RINs used for compliance during
the year being reviewed; compute and report as a finding the RIN
numbers and year of generation of RINs represented in these documents;
and agree with the report to EPA.
(2) RIN transaction report. (i) Obtain and read a copy of the RIN
transaction report required under Sec. 80.1152(a)(2) which contains
information regarding RIN trading transactions.
(ii) Obtain contracts or other documents for all RIN transactions
with another party during the year being reviewed; compute and report
as a finding the transaction types, transaction dates and RINs traded;
and agree with the report to EPA.
(3) RIN activity report. (i) Obtain and read a copy of the RIN
activity report required under Sec. 80.1152(a)(3) which contains
information regarding RIN activity for the compliance year.
(ii) Obtain documentation of all RINs acquired, used for compliance
(including current-year RINs used and previous-year RINs used)
transferred, sold, and expired during the year being reviewed; compute
and report as a finding the total RINs acquired, used for compliance,
transferred, sold, and expired as represented in these documents; and
agree with the report to EPA.
(b) The following attest procedures shall be completed for any
renewable fuel producer:
(1) Annual batch report. (i) Obtain and read a copy of the annual
batch report required under Sec. 80.1152(b)(1) which contains
information regarding renewable fuel batches.
(ii) Obtain production data for each renewable fuel batch produced
during the year being reviewed; compute and report as a finding the RIN
numbers, production dates, types, volumes of denaturant and applicable
equivalence values, and production volumes for each batch; and agree
with the report to EPA.
(iii) Verify that the proper number of RINs were generated for each
batch of renewable fuel produced, as required under Sec. 80.1126.
(iv) Obtain product transfer documents for each renewable fuel
batch produced during the year being reviewed; report as a finding any
product transfer document that did not include the RIN for the batch.
(2) RIN transaction report. (i) Obtain and read a copy of the RIN
transaction report required under Sec. 80.1152(b)(2) which contains
information regarding RIN trading transactions.
(ii) Obtain contracts or other documents for all RIN transactions
with another party during the year being reviewed; compute and report
as a finding the transaction types, transaction dates, and the RINs
traded; and agree with the report to EPA.
(3) RIN activity report. (i) Obtain and read a copy of the RIN
activity report required under Sec. 80.1152(b)(3) which contains
information regarding RIN activity for the compliance year.
(ii) Obtain documentation of all RINs owned (including RINs created
and acquired), transferred, sold and expired during the year being
reviewed; compute and report as a finding the total RINs owned,
transferred, sold and expired as represented in these documents; and
agree with the report to EPA.
(c) For each averaging period, each party subject to the attest
engagement requirements under this section shall cause the reports
required under this section to be submitted to EPA by May 31 of each
year.
Sec. 80.1165 What are the additional requirements under this subpart
for gasoline produced at foreign refineries?
(a) Definitions. The following definitions apply for this section:
(1) Foreign refinery is a refinery that is located outside the
United States, the Commonwealth of Puerto Rico, the U.S. Virgin
Islands, Guam, American Samoa, and the Commonwealth of the Northern
Mariana Islands (collectively referred to in this section as ``the
United States'').
(2) Foreign refiner is a person that meets the definition of
refiner under Sec. 80.2(i) for a foreign refinery.
(3) RFS-FRGAS is gasoline produced at a foreign refinery that has
received a small refinery exemption under Sec. 80.1141 or a small
refiner exemption under Sec. 80.1142 that is imported into the United
States.
(4) Non-RFS-FRGAS is one of the following:
(i) Gasoline produced at a foreign refinery that has received a
small refinery exemption under Sec. 80.1141 or a small refiner
exemption under Sec. 80.1142 that is not imported into the United
States.
(ii) Gasoline produced at a foreign refinery that has not received
a small refinery exemption under Sec. 80.1141 or small refiner
exemption under Sec. 80.1142.
(b) General requirements for RFS-FRGAS foreign small refiners. (1)
A foreign refiner that has a small refinery exemption under Sec.
80.1141 or a small
[[Page 55648]]
refiner exemption under Sec. 80.1142 must designate, at the time of
production, each batch of gasoline produced at the foreign refinery
that is exported for use in the United States as RFS-FRGAS; and
(2) Meet all requirements that apply to refiners who have received
a small refinery or small refiner exemption under this subpart.
(c) Designation, foreign refiner certification, and product
transfer documents. (1) Any foreign refiner that has received a small
refinery exemption under Sec. 80.1141 or a small refiner exemption
under Sec. 80.1142 must designate each batch of RFS-FRGAS as such at
the time the gasoline is produced.
(2) On each occasion when RFS-FRGAS is loaded onto a vessel or
other transportation mode for transport to the United States, the
foreign refiner shall prepare a certification for each batch of RFS-
FRGAS that meets the following requirements:
(i) The certification shall include the report of the independent
third party under paragraph (d) of this section, and the following
additional information:
(A) The name and EPA registration number of the refinery that
produced the RFS-FRGAS;
(B) [Reserved]
(ii) The identification of the gasoline as RFS-FRGAS; and,
(iii) The volume of RFS-FRGAS being transported, in gallons.
(3) On each occasion when any person transfers custody or title to
any RFS-FRGAS prior to its being imported into the United States, it
must include the following information as part of the product transfer
document information:
(i) Designation of the gasoline as RFS-FRGAS; and
(ii) The certification required under paragraph (c)(2) of this
section.
(d) Load port independent testing and refinery identification. (1)
On each occasion that RFS-FRGAS is loaded onto a vessel for transport
to the United States the small foreign refiner shall have an
independent third party:
(i) Inspect the vessel prior to loading and determine the volume of
any tank bottoms;
(ii) Determine the volume of RFS-FRGAS loaded onto the vessel
(exclusive of any tank bottoms before loading);
(iii) Obtain the EPA-assigned registration number of the foreign
refinery;
(iv) Determine the name and country of registration of the vessel
used to transport the RFS-FRGAS to the United States;
(v) Determine the date and time the vessel departs the port serving
the foreign refinery; and
(vi) Review original documents that reflect movement and storage of
the RFS-FRGAS from the foreign refinery to the load port, and from this
review determine:
(A) The refinery at which the RFS-FRGAS was produced; and
(B) That the RFS-FRGAS remained segregated from Non-RFS-FRGAS and
other RFS-FRGAS produced at a different refinery.
(2) The independent third party shall submit a report to:
(i) The foreign small refiner containing the information required
under paragraph (d)(1) of this section, to accompany the product
transfer documents for the vessel; and
(ii) The Administrator containing the information required under
paragraph (d)(1) of this section, within thirty days following the date
of the independent third party's inspection. This report shall include
a description of the method used to determine the identity of the
refinery at which the gasoline was produced, assurance that the
gasoline remained segregated as specified in paragraph (i)(1) of this
section, and a description of the gasoline's movement and storage
between production at the source refinery and vessel loading.
(3) The independent third party must:
(i) Be approved in advance by EPA, based on a demonstration of
ability to perform the procedures required in this paragraph (d);
(ii) Be independent under the criteria specified in Sec.
80.65(e)(2)(iii); and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities, facilities,
and documents relevant to compliance with the requirements of this
paragraph (d).
(e) Comparison of load port and port of entry testing. (1)(i) Any
small foreign refiner and any United States importer of RFS-FRGAS shall
compare the results from the load port testing under paragraph (d) of
this section, with the port of entry testing as reported under
paragraph (j) of this section, for the volume of gasoline, except as
specified in paragraph (e)(1)(ii) of this section.
(ii) Where a vessel transporting RFS-FRGAS off loads this gasoline
at more than one United States port of entry, the requirements of
paragraph (e)(1)(i) of this section do not apply at subsequent ports of
entry if the United States importer obtains a certification from the
vessel owner that the requirements of paragraph (e)(1)(i) of this
section were met and that the vessel has not loaded any gasoline or
blendstock between the first United States port of entry and the
subsequent port of entry.
(2) If the temperature-corrected volumes determined at the port of
entry and at the load port differ by more than one percent, the United
States importer shall include the volume of gasoline from the
importer's RFS compliance calculations.
(f) Foreign refiner commitments. Any small foreign refiner shall
commit to and comply with the provisions contained in this paragraph
(f) as a condition to being approved for a small refinery or small
refiner exemption under this subpart.
(1) Any United States Environmental Protection Agency inspector or
auditor must be given full, complete and immediate access to conduct
inspections and audits of the foreign refinery.
(i) Inspections and audits may be either announced in advance by
EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Gasoline is produced;
(B) Documents related to refinery operations are kept; and
(C) RFS-FRGAS is stored or transported between the foreign refinery
and the United States, including storage tanks, vessels and pipelines.
(iii) Inspections and audits may be by EPA employees or contractors
to EPA.
(iv) Any documents requested that are related to matters covered by
inspections and audits must be provided to an EPA inspector or auditor
on request.
(v) Inspections and audits by EPA may include review and copying of
any documents related to:
(A) The volume of RFS-FRGAS;
(B) The proper classification of gasoline as being RFS-FRGAS or as
not being RFS-FRGAS;
(C) Transfers of title or custody to RFS-FRGAS;
(D) Testing of RFS-FRGAS; and
(E) Work performed and reports prepared by independent third
parties and by independent auditors under the requirements of this
section, including work papers.
(vi) Inspections and audits by EPA may include interviewing
employees.
(vii) Any employee of the foreign refiner must be made available
for interview by the EPA inspector or auditor, on request, within a
reasonable time period.
(viii) English language translations of any documents must be
provided to an EPA inspector or auditor, on request, within 10 working
days.
(ix) English language interpreters must be provided to accompany
EPA inspectors and auditors, on request.
[[Page 55649]]
(2) An agent for service of process located in the District of
Columbia shall be named, and service on this agent constitutes service
on the foreign refiner or any employee of the foreign refiner for any
action by EPA or otherwise by the United States related to the
requirements of this subpart.
(3) The forum for any civil or criminal enforcement action related
to the provisions of this section for violations of the Clean Air Act
or regulations promulgated thereunder shall be governed by the Clean
Air Act, including the EPA administrative forum where allowed under the
Clean Air Act.
(4) United States substantive and procedural laws shall apply to
any civil or criminal enforcement action against the foreign refiner or
any employee of the foreign refiner related to the provisions of this
section.
(5) Submitting an application for a small refinery or small refiner
exemption, or producing and exporting gasoline under such exemption,
and all other actions to comply with the requirements of this subpart
relating to such exemption constitute actions or activities covered by
and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but
solely with respect to actions instituted against the foreign refiner,
its agents and employees in any court or other tribunal in the United
States for conduct that violates the requirements applicable to the
foreign refiner under this subpart, including conduct that violates the
False Statements Accountability Act of 1996 (18 U.S.C. 1001) and
section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6) The foreign refiner, or its agents or employees, will not seek
to detain or to impose civil or criminal remedies against EPA
inspectors or auditors, whether EPA employees or EPA contractors, for
actions performed within the scope of EPA employment related to the
provisions of this section.
(7) The commitment required by this paragraph (f) shall be signed
by the owner or president of the foreign refiner business.
(8) In any case where RFS-FRGAS produced at a foreign refinery is
stored or transported by another company between the refinery and the
vessel that transports the RFS-FRGAS to the United States, the foreign
refiner shall obtain from each such other company a commitment that
meets the requirements specified in paragraphs (f)(1) through (f)(7) of
this section, and these commitments shall be included in the foreign
refiner's application for a small refinery or small refiner exemption
under this subpart.
(g) Sovereign immunity. By submitting an application for a small
refinery or small refiner exemption under this subpart, or by producing
and exporting gasoline to the United States under such exemption, the
foreign refiner, and its agents and employees, without exception,
become subject to the full operation of the administrative and judicial
enforcement powers and provisions of the United States without
limitation based on sovereign immunity, with respect to actions
instituted against the foreign refiner, its agents and employees in any
court or other tribunal in the United States for conduct that violates
the requirements applicable to the foreign refiner under this subpart,
including conduct that violates the False Statements Accountability Act
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42
U.S.C. 7413).
(h) Bond posting. Any foreign refiner shall meet the requirements
of this paragraph (h) as a condition to approval as benzene foreign
refiner under this subpart.
(1) The foreign refiner shall post a bond of the amount calculated
using the following equation:
Bond = G * $ 0.01
Where:
Bond = Amount of the bond in United States dollars.
G = The largest volume of gasoline produced at the foreign refinery
and exported to the United States, in gallons, during a single
calendar year among the most recent of the following calendar years,
up to a maximum of five calendar years: the calendar year
immediately preceding the date the refinery's application is
submitted, the calendar year the application is submitted, and each
succeeding calendar year.
(2) Bonds shall be posted by:
(i) Paying the amount of the bond to the Treasurer of the United
States;
(ii) Obtaining a bond in the proper amount from a third party
surety agent that is payable to satisfy United States administrative or
judicial judgments against the foreign refiner, provided EPA agrees in
advance as to the third party and the nature of the surety agreement;
or
(iii) An alternative commitment that results in assets of an
appropriate liquidity and value being readily available to the United
States, provided EPA agrees in advance as to the alternative
commitment.
(3) Bonds posted under this paragraph (h) shall--
(i) Be used to satisfy any judicial judgment that results from an
administrative or judicial enforcement action for conduct in violation
of this subpart, including where such conduct violates the False
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii) Be provided by a corporate surety that is listed in the United
States Department of Treasury Circular 570 ``Companies Holding
Certificates of Authority as Acceptable Sureties on Federal Bonds'' and
(iii) Include a commitment that the bond will remain in effect for
at least five years following the end of latest annual reporting period
that the foreign refiner produces gasoline pursuant to the requirements
of this subpart.
(4) On any occasion a foreign refiner bond is used to satisfy any
judgment, the foreign refiner shall increase the bond to cover the
amount used within 90 days of the date the bond is used.
(5) If the bond amount for a foreign refiner increases, the foreign
refiner shall increase the bond to cover the shortfall within 90 days
of the date the bond amount changes. If the bond amount decreases, the
foreign refiner may reduce the amount of the bond beginning 90 days
after the date the bond amount changes.
(i) English language reports. Any document submitted to EPA by a
foreign refiner shall be in English language, or shall include an
English language translation.
(j) Prohibitions. (1) No person may combine RFS-FRGAS with any Non-
RFS-FRGAS, and no person may combine RFS-FRGAS with any RFS-FRGAS
produced at a different refinery, until the importer has met all the
requirements of paragraph (k) of this section.
(2) No foreign refiner or other person may cause another person to
commit an action prohibited in paragraph (j)(1) of this section, or
that otherwise violates the requirements of this section.
(k) United States importer requirements. Any United States importer
of RFS-FRGAS shall meet the following requirements:
(1) Each batch of imported RFS-FRGAS shall be classified by the
importer as being RFS-FRGAS.
(2) Gasoline shall be classified as RFS-FRGAS according to the
designation by the foreign refiner if this designation is supported by
product transfer documents prepared by the foreign refiner as required
in paragraph (c) of this section. Additionally, the importer shall
comply with all requirements of this subpart applicable to importers.
(3) For each gasoline batch classified as RFS-FRGAS, any United
States
[[Page 55650]]
importer shall have an independent third party:
(i) Determine the volume of gasoline in the vessel;
(ii) Use the foreign refiner's RFS-FRGAS certification to determine
the name and EPA-assigned registration number of the foreign refinery
that produced the RFS-FRGAS;
(iii) Determine the name and country of registration of the vessel
used to transport the RFS-FRGAS to the United States; and
(iv) Determine the date and time the vessel arrives at the United
States port of entry.
(4) Any importer shall submit reports within 30 days following the
date any vessel transporting RFS-FRGAS arrives at the United States
port of entry to:
(i) The Administrator containing the information determined under
paragraph (k)(3) of this section; and
(ii) The foreign refiner containing the information determined
under paragraph (k)(3)(i) of this section, and including identification
of the port at which the product was off loaded.
(5) Any United States importer shall meet all other requirements of
this subpart for any imported gasoline that is not classified as RFS-
FRGAS under paragraph (k)(2) of this section.
(l) Truck imports of RFS-FRGAS produced at a foreign refinery. (1)
Any refiner whose RFS-FRGAS is transported into the United States by
truck may petition EPA to use alternative procedures to meet the
following requirements:
(i) Certification under paragraph (c)(2) of this section;
(ii) Load port and port of entry testing under paragraphs (d) and
(e) of this section; and
(iii) Importer testing under paragraph (k)(3) of this section.
(2) These alternative procedures must ensure RFS-FRGAS remains
segregated from Non-RFS-FRGAS until it is imported into the United
States. The petition will be evaluated based on whether it adequately
addresses the following:
(i) Provisions for monitoring pipeline shipments, if applicable,
from the refinery, that ensure segregation of RFS-FRGAS from that
refinery from all other gasoline.
(ii) Contracts with any terminals and/or pipelines that receive
and/or transport RFS-FRGAS that prohibit the commingling of RFS-FRGAS
with Non-RFS-FRGAS or RFS-FRGAS from other foreign refineries.
(iii) Attest procedures to be conducted annually by an independent
third party that review loading records and import documents based on
volume reconciliation, or other criteria, to confirm that all RFS-FRGAS
remains segregated throughout the distribution system.
(3) The petition required by this section must be submitted to EPA
along with the application for a small refinery or small refiner
exemption under this subpart.
(m) Additional attest requirements for importers of RFS-FRGAS.
Importers of RFS-FRGAS, for each annual compliance period, must arrange
to have an attest engagement performed of the underlying documentation
that forms the basis of any report or document required under this
subpart. The attest engagement must comply with the procedures and
requirements that apply to importers under Sec. Sec. 80.125 through
80.130, and other applicable attest engagement provisions, and must be
submitted to the Administrator of EPA by August 31 of each year for the
prior annual compliance period. The following additional procedures
shall be carried out for any importer of RFS-FRGAS.
(1) Obtain listings of all tenders of RFS-FRGAS. Agree the total
volume of tenders from the listings to the gasoline inventory
reconciliation analysis in Sec. 80.128(b), and to the volumes
determined by the third party under paragraph (d) of this section.
(2) For each tender under paragraph (m)(1) of this section, where
the gasoline is loaded onto a marine vessel, report as a finding the
name and country of registration of each vessel, and the volumes of
RFS-FRGAS loaded onto each vessel.
(3) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRGAS, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform the following:
(i) Obtain the report of the independent third party, under
paragraph (d) of this section, and of the United States importer under
paragraph (k) of this section.
(A) Agree the information in these reports with regard to vessel
identification and gasoline volume.
(B) Identify, and report as a finding, each occasion the load port
and port of entry volume results differ by more than the amount allowed
in paragraph (e) of this section, and determine whether the foreign
refiner adjusted its refinery calculations as required in paragraph (e)
of this section.
(ii) Obtain the documents used by the independent third party to
determine transportation and storage of the RFS-FRGAS from the refinery
to the load port, under paragraph (d) of this section. Obtain tank
activity records for any storage tank where the RFS-FRGAS is stored,
and pipeline activity records for any pipeline used to transport the
RFS-FRGAS prior to being loaded onto the vessel. Use these records to
determine whether the RFS-FRGAS was produced at the refinery that is
the subject of the attest engagement, and whether the RFS-FRGAS was
mixed with any Non-RFS-FRGAS or any RFS-FRGAS produced at a different
refinery.
(4) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRGAS, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform the following:
(i) Obtain a commercial document of general circulation that lists
vessel arrivals and departures, and that includes the port and date of
departure of the vessel, and the port of entry and date of arrival of
the vessel.
(ii) Agree the vessel's departure and arrival locations and dates
from the independent third party and United States importer reports to
the information contained in the commercial document.
(5) Obtain separate listings of all tenders of RFS-FRGAS, and
perform the following:
(i) Agree the volume of tenders from the listings to the gasoline
inventory reconciliation analysis in Sec. 80.128(b).
(ii) Obtain a separate listing of the tenders under this paragraph
(m)(5) where the gasoline is loaded onto a marine vessel. Select a
sample from this listing in accordance with the guidelines in Sec.
80.127, and obtain a commercial document of general circulation that
lists vessel arrivals and departures, and that includes the port and
date of departure and the ports and dates where the gasoline was off
loaded for the selected vessels. Determine and report as a finding the
country where the gasoline was off loaded for each vessel selected.
(6) In order to complete the requirements of this paragraph (m) an
auditor shall:
(i) Be independent of the foreign refiner or importer;
(ii) Be licensed as a Certified Public Accountant in the United
States and a citizen of the United States, or be approved in advance by
EPA based on a demonstration of ability to perform the procedures
required in Sec. Sec. 80.125 through 80.130 and this paragraph (m);
and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities and documents
relevant to compliance
[[Page 55651]]
with the requirements of Sec. Sec. 80.125 through 80.130 and this
paragraph (m).
(n) Withdrawal or suspension of foreign refiner status. EPA may
withdraw or suspend a foreign refiner's small refinery or small refiner
exemption where--
(1) A foreign refiner fails to meet any requirement of this
section;
(2) A foreign government fails to allow EPA inspections as provided
in paragraph (f)(1) of this section;
(3) A foreign refiner asserts a claim of, or a right to claim,
sovereign immunity in an action to enforce the requirements in this
subpart; or
(4) A foreign refiner fails to pay a civil or criminal penalty that
is not satisfied using the foreign refiner bond specified in paragraph
(g) of this section.
(o) Additional requirements for applications, reports and
certificates. Any application for a small refinery or small refiner
exemption, alternative procedures under paragraph (l) of this section,
any report, certification, or other submission required under this
section shall be--
(1) Submitted in accordance with procedures specified by the
Administrator, including use of any forms that may be specified by the
Administrator.
(2) Be signed by the president or owner of the foreign refiner
company, or by that person's immediate designee, and shall contain the
following declaration: ``I hereby certify: (1) That I have actual
authority to sign on behalf of and to bind [NAME OF FOREIGN REFINER]
with regard to all statements contained herein; (2) that I am aware
that the information contained herein is being Certified, or submitted
to the United States Environmental Protection Agency, under the
requirements of 40 CFR part 80, subpart K, and that the information is
material for determining compliance under these regulations; and (3)
that I have read and understand the information being Certified or
submitted, and this information is true, complete and correct to the
best of my knowledge and belief after I have taken reasonable and
appropriate steps to verify the accuracy thereof. I affirm that I have
read and understand the provisions of 40 CFR part 80, subpart K,
including 40 CFR 80.1165 apply to [NAME OF FOREIGN REFINER]. Pursuant
to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for
furnishing false, incomplete or misleading information in this
certification or submission is a fine of up to $10,000 U.S., and/or
imprisonment for up to five years.''
[FR Doc. 06-7887 Filed 9-21-06; 8:45 am]
BILLING CODE 6560-50-P