[Federal Register Volume 74, Number 99 (Tuesday, May 26, 2009)]
[Proposed Rules]
[Pages 24904-25143]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-10978]
[[Page 24903]]
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Part II
Environmental Protection Agency
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40 CFR Part 80
Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel
Standard Program; Proposed Rule
Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed
Rules
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 80
[EPA-HQ-OAR-2005-0161; FRL-8903-1]
RIN 2060-A081
Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel
Standard Program
AGENCY: Environmental Protection Agency (EPA).
ACTION: Notice of proposed rulemaking.
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SUMMARY: Under the Clean Air Act, as amended by Sections 201, 202, and
210 of the Energy Independence and Security Act of 2007, the
Environmental Protection Agency is required to promulgate regulations
implementing changes to the Renewable Fuel Standard program. The
revised statutory requirements specify the volumes of cellulosic
biofuel, biomass-based diesel, advanced biofuel, and total renewable
fuel that must be used in transportation fuel each year, with the
volumes increasing over time. The revised statutory requirements also
include new definitions and criteria for both renewable fuels and the
feedstocks used to produce them, including new greenhouse gas emission
thresholds for renewable fuels. For the first time in a regulatory
program, an assessment of greenhouse gas emission performance is being
utilized to establish those fuels that qualify for the four different
renewable fuel standards. As mandated by the revised statutory
requirements, the greenhouse gas emission assessments must evaluate the
full lifecycle emission impacts of fuel production including both
direct and indirect emissions, including significant emissions from
land use changes. The proposed program is expected to reduce U.S.
dependence on foreign sources of petroleum by increasing domestic
sources of energy. Based on our lifecycle analysis, we believe that the
expanded use of renewable fuels would provide significant reductions in
greenhouse gas emissions such as carbon dioxide that affect climate
change. We recognize the significance of using lifecycle greenhouse gas
emission assessments that include indirect impacts such as emission
impacts of indirect land use changes. Therefore, in this preamble we
have been transparent in breaking out the various sources of greenhouse
gas emissions included in the analysis and are seeking comments on our
methodology as well as various options for determining the lifecycle
greenhouse gas emissions (GHG) for each fuel. In addition to seeking
comments on the information in this document and its supporting
materials, the Agency is conducting peer reviews of critical aspects of
the lifecycle methodology. The increased use of renewable fuels would
also impact criteria pollutant emissions, with some pollutants such as
volatile organic compounds (VOC) and nitrogen oxides (NOX)
expected to increase and other pollutants such as carbon monoxide (CO)
and benzene expected to decrease. The production of feedstocks used to
produce renewable fuels is also expected to impact water quality.
This action proposes regulations designed to ensure that refiners,
blenders, and importers of gasoline and diesel would use enough
renewable fuel each year so that the four volume requirements of the
Energy Independence and Security Act would be met with renewable fuels
that also meet the required lifecycle greenhouse gas emissions
performance standards. Our proposed rule describes the standards that
would apply to these parties and the renewable fuels that would qualify
for compliance. The proposed regulations make a number of changes to
the current Renewable Fuel Standard program while retaining many
elements of the compliance and trading system already in place.
DATES: Comments must be received on or before July 27, 2009, 60 days
after publication in the Federal Register. Under the Paperwork
Reduction Act, comments on the information collection provisions are
best assured of having full effect if the Office of Management and
Budget (OMB) receives a copy of your comments on or before June 25,
2009, 30 days after date of publication in the Federal Register.
Hearing: We will hold a public hearing on June 9, 2009 at the
Dupont Hotel in Washington, DC. The hearing will start at 10 a.m. local
time and continue until everyone has had a chance to speak. If you want
to testify at the hearing, notify the contact person listed under FOR
FURTHER INFORMATION CONTACT by June 1, 2009.
Workshop: We will hold a workshop on June 10-11, 2009 at the Dupont
Hotel in Washington, DC to present details of our lifecycle GHG
analysis. During this workshop, we intend to go through the lifecycle
GHG analysis included in this proposal. The intent of this workshop is
to help ensure a full understanding of our lifecycle analysis, the
major issues identified and the options discussed. We expect that this
workshop will help ensure that we receive submission of the most
thoughtful and useful comments to this proposal and that the best
methodology and assumptions are used for calculating GHG emissions
impacts of fuels for the final rule. While this workshop will be held
during the comment period, it is not intended to replace either the
formal public hearing or the need to submit comments to the docket.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2005-0161, by one of the following methods:
www.regulations.gov: Follow the on-line instructions for
submitting comments.
E-mail: [email protected].
Mail: Air and Radiation Docket and Information Center,
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460. In addition, please mail a copy of
your comments on the information collection provisions to the Office of
Information and Regulatory Affairs, Office of Management and Budget
(OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC
20503.
Hand Delivery: EPA Docket Center, EPA West Building, Room
3334, 1301 Constitution Ave., NW., Washington, DC 20004. Such
deliveries are only accepted during the Docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2005-0161. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through www.regulations.gov or e-mail.
The www.regulations.gov Web site is an ``anonymous access'' system,
which means EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an e-
mail comment directly to EPA without going through www.regulations.gov
your e-mail address will be automatically captured and included as part
of the comment that is placed in the public docket and made available
on the Internet. If you submit an electronic comment, EPA recommends
that you include your name and other contact information in the body of
your
[[Page 24905]]
comment and with any disk or CD-ROM you submit. If EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses. For additional
information about EPA's public docket visit the EPA Docket Center
homepage at http://www.epa.gov/epahome/dockets.htm. For additional
instructions on submitting comments, go to Section XI, Public
Participation, of the SUPPLEMENTARY INFORMATION section of this
document.
Docket: All documents in the docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the Air and Radiation Docket
and Information Center, EPA/DC, EPA West, Room 3334, 1301 Constitution
Ave., NW., Washington, DC. The Public Reading Room is open from 8:30
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The
telephone number for the Public Reading Room is (202) 566-1744, and the
telephone number for the Air Docket is (202) 566-1742.
Hearing: The public hearing will be held on June 9, 2009 at the
Dupont Hotel, 1500 New Hampshire Avenue, NW., Washington, DC 20036. See
Section XI, Public Participation, for more information about the public
hearing.
FOR FURTHER INFORMATION CONTACT: Julia MacAllister, Office of
Transportation and Air Quality, Assessment and Standards Division,
Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI
48105; Telephone number: 734-214-4131; Fax number: 734-214-4816; E-mail
address: [email protected], or Assessment and Standards
Division Hotline; telephone number (734) 214-4636; E-mail address
[email protected].
SUPPLEMENTARY INFORMATION:
General Information
A. Does This Proposal Apply to Me?
Entities potentially affected by this proposal are those involved
with the production, distribution, and sale of transportation fuels,
including gasoline and diesel fuel or renewable fuels such as ethanol
and biodiesel. Regulated categories include:
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NAICS \1\ SIC \2\
Category codes codes Examples of potentially regulated entities
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Industry..................................... 324110 2911 Petroleum Refineries.
Industry..................................... 325193 2869 Ethyl alcohol manufacturing.
Industry..................................... 325199 2869 Other basic organic chemical manufacturing.
Industry..................................... 424690 5169 Chemical and allied products merchant wholesalers.
Industry..................................... 424710 5171 Petroleum bulk stations and terminals.
Industry..................................... 424720 5172 Petroleum and petroleum products merchant wholesalers.
Industry..................................... 454319 5989 Other fuel dealers.
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\1\ North American Industry Classification System (NAICS).
\2\ Standard Industrial Classification (SIC) system code.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
proposed action. This table lists the types of entities that EPA is now
aware could potentially be regulated by this proposed action. Other
types of entities not listed in the table could also be regulated. To
determine whether your activities would be regulated by this proposed
action, you should carefully examine the applicability criteria in 40
CFR part 80. If you have any questions regarding the applicability of
this proposed action to a particular entity, consult the person listed
in the preceding FOR FURTHER INFORMATION CONTACT section.
B. What Should I Consider as I Prepare My Comments for EPA?
1. Submitting CBI
Do not submit this information to EPA through www.regulations.gov
or e-mail. Clearly mark the part or all of the information that you
claim to be confidential business information (CBI). For CBI
information in a disk or CD-ROM that you mail to EPA, mark the outside
of the disk or CD-ROM as CBI and then identify electronically within
the disk or CD-ROM the specific information that is claimed as CBI. In
addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.
2. Tips for Preparing Your Comments
When submitting comments, remember to:
Explain your views as clearly as possible.
Describe any assumptions that you used.
Provide any technical information and/or data you used
that support your views.
If you estimate potential burden or costs, explain how you
arrived at your estimate.
Provide specific examples to illustrate your concerns.
Offer alternatives.
Make sure to submit your comments by the comment period
deadline identified.
To ensure proper receipt by EPA, identify the appropriate
docket identification number in the subject line on the first page of
your response. It would also be helpful if you provided the name, date,
and Federal Register citation related to your comments.
We are primarily seeking comment on the proposed 40 CFR Part 80
Subpart M regulatory language that is not directly included in 40 CFR
Part 80 Subpart K. For the proposed subpart M regulatory language that
is unchanged from subpart K, we are only soliciting comment as it
relates to its use for the RFS2 rule.
Outline of This Preamble
I. Introduction
A. Renewable Fuels and the Transportation Sector
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B. Renewable Fuels and Greenhouse Gas Emissions
C. Building on the RFS1 Program
II. Overview of the Proposed Program
A. Summary of New Provisions of the RFS Program
1. Required Volumes of Renewable Fuel
2. Changes in How Renewable Fuel Is Defined
3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds
for Renewable Fuels
4. Coverage Expanded to Transportation Fuel, Including Diesel
and Nonroad Fuels
5. Effective Date for New Requirements
6. Treatment of Required Volumes Preceding the RFS2 Effective
Date
7. Waivers and Credits for Cellulosic Biofuel
8. Proposed Standards for 2010
B. Impacts of Increasing Volume Requirements in the RFS2 Program
1. Greenhouse Gases and Fossil Fuel Consumption
2. Economic Impacts and Energy Security
3. Emissions, Air Quality, and Health Impacts
4. Water
5. Agricultural Commodity Prices
III. What Are the Major Elements of the Program Required Under EISA?
A. Changes to Renewable Identification Numbers (RINs)
B. New Eligibility Requirements for Renewable Fuels
1. Changes in Renewable Fuel Definitions
a. Renewable Fuel and Renewable Biomass
b. Advanced Biofuel
c. Cellulosic Biofuel
d. Biomass-Based Diesel
e. Additional Renewable Fuel
2. Lifecycle GHG Thresholds
3. Renewable Fuel Exempt From 20 Percent GHG Threshold
a. Definition of Commence Construction
b. Definition and Boundaries of a Facility
c. Options Proposed in Today's Rulemaking
i. Basic Approach: Grandfathering Limited to Baseline Volumes
(1) Increases in volume of renewable fuel produced at
grandfathered facilities due to expansion
(2) Replacements of equipment
(3) Registration, Recordkeeping and Reporting
(4) Sub-option of treatment of future modifications
ii. Alternative Options for Which We Seek Comment
(1) Facilities that meet the definition of ``reconstruction''
are considered new
(2) Expiration date of 15 years for exempted facilities
(3) Expiration date of 15 years for grandfathered facilities and
limitation on volume
(4) ``Significant production units'' are defined as facilities
(5) Indefinite grandfathering and no limitations placed on
volume
4. Renewable Biomass with Land Restrictions
a. Definitions of Terms
i. Planted Crops and Crop Residue
ii. Planted Trees and Tree Residue
iii. Slash and Pre-Commercial Thinnings
iv. Biomass Obtained From Certain Areas at Risk From Wildfire
b. Issues Related to Implementation and Enforceability
i. Ensuring That RINs Are Generated Only for Fuels Made From
Renewable Biomass
ii. Ensuring That RINs Are Generated for All Qualifying
Renewable Fuel
c. Review of Existing Programs
i. USDA Programs
ii. Third-Party Programs
d. Approaches for Domestic Renewable Fuel
e. Approaches for Foreign Renewable Fuel
C. Expanded Registration Process for Producers and Importers
1. Domestic Renewable Fuel Producers
2. Foreign Renewable Fuel Producers
3. Renewable Fuel Importers
4. Process and Timing
D. Generation of RINs
1. Equivalence Values
2. Fuel Pathways and Assignment of D Codes
a. Domestic Producers
b. Foreign Producers
c. Importers
3. Facilities With Multiple Applicable Pathways
4. Facilities That Co-Process Renewable Biomass and Fossil Fuels
5 Treatment of Fuels Without an Applicable D Code
6. Carbon Capture and Storage (CCS)
E. Applicable Standards
1. Calculation of Standards
a. How Would the Standards Be Calculated?
b. Proposed Standards for 2010
c. Projected Standards for Other Years
d. Alternative Effective Date
2. Treatment of Biomass-Based Diesel in 2009 and 2010
a. Proposed Shift in Biomass-Based Diesel Requirement from 2009
to 2010
i. First Option for Treatment of 2009 Biodiesel and Renewable
Diesel RINs
ii. Second Option for Treatment of 2009 Biodiesel and Renewable
Diesel RINs
b. Proposed Treatment of Deficit Carryovers and Valid RIN Life
for Adjusted 2010 Biomass-Based Diesel Requirement
c. Alternative Approach to Treatment of Biomass-Based Diesel in
2009 and 2010
F. Fuels That Are Subject to the Standards
1. Gasoline
2. Diesel
3. Other Transportation Fuels
G. Renewable Volume Obligations (RVOs)
1. Determination of RVOs Corresponding to the Four Standards
2. RINs Eligible to Meet Each RVO
3. Treatment of RFS1 RINs under RFS2
a. Use of 2009 RINs in 2010
b. Deficit Carryovers from the RFS1 Program to RFS2
4. Alternative Approach to Designation of Obligated Parties
H. Separation of RINs
1. Nonroad
2. Heating Oil and Jet Fuel
3. Exporters
4. Alternative Approaches to RIN Transfers
5. Neat Renewable Fuel and Renewable Fuel Blends Designated as
Transportation Fuel, Home Heating Oil, or Jet Fuel
I. Treatment of Cellulosic Biofuel
1. Cellulosic Biofuel Standard
2. EPA Cellulosic Allowances for Cellulosic Biofuel
3. Potential Adverse Impacts of Allowances
J. Changes to Recordkeeping and Reporting Requirements
1. Recordkeeping
2. Reporting
3. Additional Requirements for Producers of Renewable Natural
Gas, Electricity, and Propane
K. Production Outlook Reports
L. What Acts Are Prohibited and Who Is Liable for Violations?
IV. What Other Program Changes Have We Considered?
A. Attest Engagements
B. Small Refinery and Small Refiner Flexibilities
1. Small Refinery Temporary Exemption
2. Small Refiner Flexibilities
a. Extension of Existing RFS1 Temporary Exemption
b. Program Review
c. Extensions of the Temporary Exemption Based on
Disproportionate Economic Hardship
d. Phase-in
e. RIN-Related Flexibilities
C. Other Flexibilities
1. Upward Delegation of RIN-Separating Responsibilities
2. Small Producer Exemption
D. 20% Rollover Cap
E. Concept for EPA Moderated Transaction System
2. How EMTS Would Work
3. Implementation of EMTS
F. Retail Dispenser Labelling for Gasoline with Greater than 10
Percent Ethanol
V. Assessment of Renewable Fuel Production Capacity and Use
A. Summary of Projected Volumes
1. Reference Case
2. Control Case for Analyses
a. Cellulosic Biofuel
b. Biomass-Based Diesel
c. Other Advanced Biofuel
d. Other Renewable Fuel
B. Renewable Fuel Production
1. Corn/Starch Ethanol
a. Historic/Current Production
b. Forecasted Production Under RFS2
2. Cellulosic Ethanol
a. Current Production/Plans
b. Federal/State Production Incentives
c. Feedstock Availability
i Urban Waste
ii. Agricultural and Forestry Residues
iii Dedicated Energy Crops
iv. Summary of Cellulosic Feedstocks for 2022
v. Cellulosic Plant Siting
3. Imported Ethanol
a. Historic World Ethanol Production and Consumption
b. Historic/Current Domestic Imports
c. Projected Domestic Imports
4. Biodiesel & Renewable Diesel
a. Historic and Projected Production
i. Biodiesel
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ii. Renewable Diesel
b. Feedstock Availability
C. Renewable Fuel Distribution
1. Overview of Ethanol Distribution
2. Overview of Biodiesel Distribution
3. Overview of Renewable Diesel Distribution
4. Changes in Freight Tonnage Movements
5. Necessary Rail System Accommodations
6. Necessary Marine System Accommodations
7. Necessary Accommodations to the Road Transportation System
8. Necessary Terminal Accommodations
9. Need for Additional E85 Retail Facilities
D. Ethanol Consumption
1. Historic/Current Ethanol Consumption
2. Increased Ethanol Use under RFS2
a. Projected Gasoline Energy Demand
b. Projected Growth in Flexible Fuel Vehicles
c. Projected Growth in E85 Access
d. Required Increase in E85 Refueling Rates
e. Market Pricing of E85 Versus Gasoline
3. Other Mechanisms for Getting Beyond the E10 Blend Wall
a. Mandate for FFV Production
b. Waiver of Mid-Level Ethanol Blends (E15/E20)
c. Partial Waiver for Mid-Level Blends
d. Non-Ethanol Cellulosic Biofuel Production
e. Measurement Tolerance for E10
f. Redefining ``Substantially Similar'' to Allow Mid-Level
Ethanol Blends
VI. Impacts of the Program on Greenhouse Gas Emissions
A. Introduction
1. Definition of Lifecycle GHG Emissions
2. History and Evolution of GHG Lifecycle Analysis
B. Methodology
1. Scenario Description
2. Scope of the Analysis
a. Legal Interpretation of Lifecycle Greenhouse Gas Emissions
b. System Boundaries
3. Modeling Framework
4. Treatment of Uncertainty
5. Components of the Lifecycle GHG Emissions Analysis
a. Feedstock Production
i. Domestic Agricultural Sector Impacts
ii. International Agricultural Sector GHG Impacts
b. Land Use Change
i. Amount of Land Converted
ii. Where Land Is Converted
iii. What Type of Land Is Converted
iv. What Are the GHG Emissions Associated with Different Types
of Land Conversion
v. Assessing GHG Emissions Impacts Over Time and Potential
Application of a GHG Discount Rate
c. Feedstock Transport
d. Processing
e. Fuel Transport
f. Tailpipe Combustion
6. Petroleum Baseline
7. Energy Sector Indirect Impacts
C. Fuel Specific GHG Emissions Estimates
1. Greenhouse Gas Emissions Reductions Relative to the 2005
Petroleum Baseline
a. Corn Ethanol
b. Imported Ethanol
c. Cellulosic Ethanol
d. Biodiesel
2. Treatment of GHG Emissions Over Time
D. Thresholds
E. Assignment of Pathways to Renewable Fuel Categories
1. Statutory Requirements
2. Assignments for Pathways Subjected to Lifecycle Analyses
3. Assignments for Additional Pathways
a. Ethanol From Starch
b. Renewable Fuels from Cellulosic Biomass
c. Biodiesel
d. Renewable Diesel Through Hydrotreating
4. Summary
F. Total GHG Emission Reductions
G. Effects of GHG Emission Reductions and Changes in Global
Temperature and Sea Level
1. Introduction
2. Estimated Projected Reductions in Global Mean Surface
Temperatures
VII. How Would the Proposal Impact Criteria and Toxic Pollutant
Emissions and Their Associated Effects?
A. Overview of Impacts
B. Fuel Production & Distribution Impacts of the Proposed
Program
C. Vehicle and Equipment Emission Impacts of Fuel Program
D. Air Quality Impacts
1. Current Levels of PM2.5, Ozone and Air Toxics
2. Impacts of Proposed Standards on Future Ambient
Concentrations of PM2.5, Ozone and Air Toxics
E. Health Effects of Criteria and Air Toxic Pollutants
1. Particulate Matter
a. Background
b. Health Effects of PM
2. Ozone
a. Background
b. Health Effects of Ozone
3. Carbon Monoxide
4. Air Toxics
a. Acetaldehyde
b. Acrolein
c. Benzene
d. 1,3-Butadiene;
e. Ethanol
f. Formaldehyde
g. Naphthalene
h. Peroxyacetyl nitrate (PAN)
i. Other Air Toxics
F. Environmental Effects of Criteria and Air Toxic Pollutants
1. Visibility
2. Atmospheric Deposition
3. Plant and Ecosystem Effects of Ozone
4. Welfare Effects of Air Toxics
VIII. Impacts on Cost of Renewable Fuels, Gasoline, and Diesel
A. Renewable Fuel Production Costs
1. Ethanol Production Costs
a. Corn Ethanol
b. Cellulosic Ethanol
i. Feedstock Costs
ii. Production Costs
c. Imported Sugarcane Ethanol
2. Biodiesel and Renewable Diesel Production Costs
a. Biodiesel
b. Renewable Diesel
3. BTL Diesel Production Costs
B. Distribution Costs
1. Ethanol Distribution Costs
a. Capital Costs to Upgrade the Distribution System for
Increased Ethanol Volume
b. Ethanol Freight Costs
2. Biodiesel and Renewable Diesel Distribution Costs
a. Capital Costs to Upgrade the Distribution System for
Increased FAME Biodiesel Volume
b. Biodiesel Freight Costs
c. Renewable Diesel Distribution System Capital and Freight
Costs
C. Reduced Refining Industry Costs
D. Total Estimated Cost Impacts
1. Refinery Modeling Methodology
2. Overall Impact on Fuel Cost
a. Costs Without Federal Tax Subsidies
b. Gasoline and Diesel Costs Reflecting the Tax Subsidies
IX. Economic Impacts and Benefits of the Proposal
A. Agricultural Impacts
1. Commodity Price Changes
2. Impacts on U.S. Farm Income
3. Commodity Use Changes
4. U.S. Land Use Changes
5. Impact on U.S. Food Prices
6. International Impacts
B. Energy Security Impacts
1. Implications of Reduced Petroleum Use on U.S. Imports
2. Energy Security Implications
a. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs,
and Economic Output
b. Short-Run Disruption Premium from Expected Costs of Sudden
Supply Disruptions
c. Costs of Existing U.S. Energy Security Policies
d. Anticipated Future Effort
e. Total Energy Security Benefits
C. Benefits of Reducing GHG Emissions
1. Introduction
2. Marginal GHG Benefits Estimates
3. Discussion of Marginal GHG Benefits Estimates
4. Total Monetized GHG Benefits Estimates
D. Co-pollutant Health and Environmental Impacts
1. Human Health and Environmental Impacts
2. Monetized Impacts
3. Other Unquantified Health and Environmental Impacts
E. Economy-Wide Impacts
X. Impacts on Water
A. Background
1. Ecological Impacts
2. Gulf of Mexico
B. Upper Mississippi River Basin Analysis
1. SWAT Model
2. Baseline Model Scenario
3. Alternative Scenarios
C. Additional Water Issues
1. Chesapeake Bay Watershed
2. Ethanol Production
a. Distillers Grain with Solubles
b. Ethanol Leaks and Spills
3. Biodiesel Plants
4. Water Quantity
5. Drinking Water
D. Request for Comment on Options for Reducing Water Quality
Impacts
XI. Public Participation
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A. How Do I Submit Comments?
B. How Should I Submit CBI to the Agency?
C. Will There Be a Public Hearing?
D. Comment Period
E. What Should I Consider as I Prepare My Comments for EPA?
XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
1. Overview
2. Background
3. Summary of Potentially Affected Small Entities
4. Potential Reporting, Record Keeping, and Compliance
5. Related Federal Rules
6. Summary of SBREFA Panel Process and Panel Outreach
a. Significant Panel Findings
b. Panel Process
c. Panel Recommendations
i. Delay in Standards
ii. Phase-in
iii. RIN-Related Flexibilities
iv. Program Review
v. Extensions of the Temporary Exemption Based on a Study of
Small Refinery Impacts
vi. Extensions of the Temporary Exemption Based on
Disproportionate Economic Hardship
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer Advancement Act
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
XIII. Statutory Authority
I. Introduction
The current Renewable Fuel Standard program (RFS1) was originally
adopted by EPA to implement the provisions of the Energy Policy Act of
2005 (EPAct), which added section 211(o) to the Clean Air Act (CAA).
With the passage of the Energy Independence and Security Act of 2007
(EISA), Congress recently made several important revisions to these
renewable fuel requirements. This Notice proposes to revise the RFS
program regulations to implement these EISA provisions. The proposed
changes would apply starting January 1, 2010. For the remainder of
2009, the current RFS1 regulations would apply. However, in
anticipation of the biomass-based diesel standard proposed for 2010,
obligated parties may find it in their best interest to plan
accordingly in 2009.
A. Renewable Fuels and the Transportation Sector
For the past several years, U.S. renewable fuel use has been
rapidly increasing for a number of reasons. In the early 1990's,
certain oxygenated gasoline fuel programs required by the CAA
amendments of 1990 established new market opportunities for renewable
fuels, primarily ethanol. At the same time, growing concern over U.S.
dependence on foreign sources of crude placed increasing focus on
renewable fuels as a replacement for petroleum-based fuels. More
recently, several state bans on the use of methyl tertiary butyl ether
(MTBE) in gasoline resulted in a large, sudden increase in demand for
ethanol. Perhaps the largest impact on renewable fuel demand, however,
has been the dramatic increase in the cost of crude oil. In the last
few years, both crude oil prices and crude oil price forecasts have
increased dramatically, which have resulted in a large economic
incentive for the increased development and use of renewable fuels.
In 2005, Congress introduced a new approach to supporting renewable
fuels. EPAct established a major new federal renewable fuel volume
mandate. EPAct required a ramp up to 7.5 billion gallons of renewable
fuel as motor vehicle fuel by 2012 and set annual volume targets for
each year leading up to 2012. For 2013 and beyond, EPA was directed to
establish the annual required renewable fuel volumes, but at a
percentage level no less than that required for 2012. While the market
forces described above ultimately caused renewable fuel use to far
exceed the EPAct mandates, this program provided certainty that at
least a minimum amount of renewable fuel would be used in the U.S.
transportation market, which in turn provided assurance for investment
in production capacity.
The subsequent passage of EISA made significant changes to both the
structure and the magnitude of the renewable fuel program. The
renewable fuel program established by EISA, hereafter referred to as
RFS2, mandates the use of 36 billion gallons of renewable fuel by 2022.
This is nearly a five-fold increase over the highest volume specified
by EPAct and constitutes a 10-year extension of the scheduled
production ramp-up period provided for in that legislation. It is clear
that the volumes required by EISA will push the market to new levels--
far beyond what current market conditions would achieve alone. In
addition, EISA specifies four separate categories of renewable fuels,
each with a separate volume mandate. The categories are renewable fuel,
advanced biofuel, biomass-based diesel, and cellulosic biofuel. There
is a notable increase in the mandate for cellulosic biofuels in
particular. EISA increased the cellulosic biofuel mandate from 250
million in EPAct to 1.0 billion gallons by 2013, with additional yearly
increases to 16 billion gallons by 2022. These requirements will
provide a strong foundation for investment in cellulosic production and
position cellulosic fuel to become a major portion of the renewable
fuel pool over the next decade.
The implications of the volume expansion of the program are not
trivial. Development of infrastructure capable of delivering, storing
and blending these volumes in new markets and expanding existing market
capabilities will be needed. For example, the market's absorption of
increased volumes of ethanol may ultimately require new ``outlets''
beyond E10 blends (i.e., gasoline containing 10% ethanol by volume),
such as an expansion of the number of flexible-fuel E85 vehicles and
the number of retail outlets selling E85.
B. Renewable Fuels and Greenhouse Gas Emissions
Another significant aspect of the RFS2 program is the focus on the
greenhouse gas impact of renewable fuels, from a lifecycle perspective.
The lifecycle GHG emissions means the aggregate quantity of GHGs
related to the full fuel cycle, including all stages of fuel and
feedstock production and distribution, from feedstock generation and
extraction through distribution and delivery and use of the finished
fuel. EISA established specific greenhouse gas emission thresholds for
each of four types of renewable fuels, requiring a percentage
improvement compared to a baseline of the gasoline and diesel used in
2005. EPA must conduct a lifecycle analysis to determine whether or not
renewable fuels produced under varying conditions will meet the
greenhouse gas (GHG) thresholds for the different fuel types for which
EISA establishes mandates. While these thresholds do not constitute a
control on greenhouse gases for transportation fuels (such as a low
carbon fuel standard),\1\ they do require that the volume mandates be
met through the use of renewable fuels that meet certain lifecycle GHG
reduction thresholds when compared to
[[Page 24909]]
the baseline lifecycle emissions of petroleum fuel they replace.
Compliance with the thresholds requires a comprehensive evaluation of
renewable fuels, as well as of gasoline and diesel, on the basis of
their lifecycle emissions. As mandated by EISA, the greenhouse gas
emission assessments must evaluate the full lifecycle emission impacts
of fuel production including both direct and indirect emissions,
including significant emissions from land use changes. We recognize the
significance of using lifecycle greenhouse gas emission assessments
that include indirect impacts such as emission impacts of indirect land
use changes. Therefore, in this preamble, we have been transparent in
breaking out the various sources of greenhouse gas emissions included
in the analysis. As described in detail in Section VI, EPA has analyzed
the lifecycle GHG impacts of the range of biofuels currently expected
to contribute significantly to meeting the volume mandates of EISA
through 2022. In these analyses we have used the best science
available. Our analysis relies on peer reviewed models and the best
estimate of important trends in agricultural practices and fuel
production technologies as these may impact our prediction of
individual biofuel GHG performance through 2022. We have identified and
highlighted assumptions and model inputs that particularly influence
our assessment and seek comment on these assumptions, the models we
have used and our overall methodology so as to assure the most robust
assessment of lifecycle GHG performance for the final rule.
---------------------------------------------------------------------------
\1\ See Section IV.D of EPA's advanced notice of proposed
rulemaking, Regulating Greenhouse Gas Emissions under the Clean Air
Act, for a discussion of EPA's possible authority under section
211(c) of the CAA to establish GHG standards for renewable and
alternative fuels. 73 FR 44354, July 30, 2008.
---------------------------------------------------------------------------
Because lifecycle analysis is a new part of the RFS program, in
addition to the formal comment period on the proposed rule, EPA is
making multiple efforts to solicit public and expert feedback on our
proposed approach. EPA plans to hold a public workshop focused
specifically on lifecycle analysis during the comment period to assure
full understanding of the analyses conducted, the issues addressed and
the options that are discussed. We expect that this workshop will help
ensure that we receive submission of the most thoughtful and useful
comments to this proposal and that the best methodology and assumptions
are used for calculating GHG emissions impacts of fuels for the final
rule. Additionally, between this proposal and the final rule, we will
conduct peer-reviews of key components of our analysis. As explained in
more detail in the Section VI, EPA is specifically seeking peer review
of: Our use of satellite data to project future the type of land use
changes; the land conversion GHG emissions factors estimates we have
used for different types of land use; our estimates of GHG emissions
from foreign crop production; methods to account for the variable
timing of GHG emissions; and how the several models we have relied upon
are used together to provide overall lifecycle GHG estimates.
In addition to the GHG thresholds, EISA included several provisions
for the RFS2 program designed to address the long-term environmental
sustainability of expanded biofuels production. The new law limits the
crops and crop residues used to produce renewable fuel to those grown
on land cleared or cultivated at any time prior to enactment of EISA,
that is either actively managed or fallow, and non-forested. EISA also
generally requires that forest-related slash and tree thinnings used
for renewable fuel production pursuant to the Act be harvested from
non-federal forest lands.
To address potential air quality concerns, EPA is required by
section 209 of EISA to determine whether the RFS2 volumes will
adversely impact air quality as a result of changes in vehicle and
engine emissions and then to issue fuel regulations that mitigate--to
the extent achievable--these impacts. The Agency is also required by
section 204 of EISA to conduct a broad study of environmental and
resource conservation impacts of EISA, including impacts on water
quality and availability, soil conservation, and biodiversity. Congress
set specific deadlines for both of these provisions, which are separate
from this rulemaking and will be carried out as part of a future
effort. However, this NPRM does include EPA's initial assessment of the
air and water quality impacts of the EISA volumes.
While the above described changes are significant, it is important
to note that Congress left other structural elements of the RFS program
basically intact. The various modifications are discussed throughout
this preamble.
C. Building on the RFS1 Program
In designing this proposed RFS2 program, the Agency is utilizing
and building on the same programmatic structure created to implement
the current renewable fuel program (hereafter referred to as RFS1). For
example, we propose to continue to use the Renewable Identification
Number (RIN) system currently in place to track compliance with the
RFS1 program, with modifications to implement the EISA provisions. This
approach is in keeping with the Agency's overall intent for RFS1--to
design a flexible and enforceable system that could continue to operate
effectively regardless of the level of renewable fuel use or market
conditions in the transportation fuel sector.
A key component of the Agency's work to build a successful RFS1
program was early and sustained engagement with our stakeholders. In
developing this proposed rulemaking, we have again worked closely with
a wide variety of stakeholders. Because EISA created new obligated
parties and established new, complex provisions such as the lifecycle
GHG thresholds and previous cropland requirements, EPA has extended its
stakeholder engagement to include dozens of meetings with stakeholders
from a broad spectrum of perspectives. For example, the Agency has had
multiple meetings and discussions with renewable fuel producers,
technology companies, petroleum refiners and importers, agricultural
associations, lifecycle experts, environmental groups, vehicle
manufacturers, states, gasoline and petroleum marketers, pipeline
owners and fuel terminal operators.
II. Overview of the Proposed Program
This section provides an overview of the RFS2 program requirements
that EPA proposes to implement as a result of EISA. The RFS2 program
would replace the RFS1 program promulgated on May 1, 2007 (72 FR
23900).\2\ We are also proposing a number of changes to make the
program more flexible based on what we learned from the operation of
the RFS1 program since it began on September 1, 2007. Details of the
proposed requirements can be found in Sections III and IV. We request
comment on our proposed regulatory requirements and the alternatives
that we have considered.
---------------------------------------------------------------------------
\2\ To meet the requirements of EPAct, EPA had previously
adopted a limited program that applied only to calendar year 2006.
The RFS1 program refers to the general program adopted in the May
2007 rulemaking.
---------------------------------------------------------------------------
This section also provides a summary of EPA's impacts assessment of
the use of higher renewable fuel volumes. Impacts that we assessed
include: emissions of pollutants such as greenhouse gases (GHG), oxides
of nitrogen (NOX), hydrocarbons, particulate matter (PM),
and toxics; reductions in petroleum use and related impacts on national
energy security; impacts on the agriculture sector; impacts on costs of
transportation fuels; economic costs and benefits; and impacts on
water. Details of these
[[Page 24910]]
analyses can be found in Sections V through X and in the Draft
Regulatory Impact Analysis (DRIA).
A. Summary of New Provisions of the RFS Program
Today's notice proposes new regulatory requirements for the RFS
program that would be implemented through a new Subpart M to 40 CFR
Part 80. EPA is generally proposing to maintain many elements of the
RFS1 program such as regulations governing the generation, transfer,
and use of Renewable Identification Numbers (RINs). At the same time,
we seek comment on a number of RFS1 provisions that may require
adjustment under an expanded RFS2 program, including whether or not to
require that all qualifying renewable fuels have RINs generated for it
(discussed in Section III.B.4.b.ii), and whether a rollover cap on RINs
other than 20 percent might be appropriate (discussed in Section IV.D).
Furthermore, EPA is proposing several new provisions and seeking
comment on alternatives on aspects of the program for which EISA grants
EPA discretion and flexibility, such as the grandfathering of existing
renewable fuel production facilities (discussed in Section III.B.3),
the potential inclusion of electricity for credit (discussed in Section
III.B.1.a), and how renewable fuels are categorized based on the
results of lifecycle analyses (discussed in Section VI.B). We believe
these and other aspects of the program are important because they will
affect available volumes of qualifying renewable fuel, regulated
parties' ability to comply with the program and, ultimately, the
program's environmental and societal impacts. A full description of all
the changes we are proposing to the RFS program to implement the
requirements in EISA is provided in Section III, while Section IV
includes extensive discussion of other changes to the RFS program under
consideration.
1. Required Volumes of Renewable Fuel
The primary purpose of the RFS program is to require a minimum
volume of renewable fuel to be used each year in the transportation
sector. Under RFS1, the required volume was 4.0 billion gallons in
2006, ramping up to 7.5 billion gallons by 2012. Starting in 2013,
EPAct required that the total volume of renewable fuel represent at
minimum the same volume fraction of the gasoline fuel pool as it did in
2012, and that the total volume of renewable fuel contains at least 250
million gallons of fuel derived from cellulosic biomass.
EISA makes three primary changes to the volume requirements of the
RFS program. First, it substantially increases the required volumes and
extends the timeframe over which the volumes ramp up through at least
2022. Second, it divides the total renewable fuel requirement into four
separate categories, each with its own volume requirement. Third, it
requires that each of these mandated volumes of renewable fuels achieve
certain minimum thresholds of GHG emission performance. The volume
requirements in EISA are shown in Table II.A.1-1.
Table II.A.1-1--Renewable Fuel Volume Requirements for RFS2
[Billion gallons]
----------------------------------------------------------------------------------------------------------------
Cellulosic Biomass- based Advanced Total
biofuel diesel biofuel renewable fuel
requirement requirement requirement requirement
----------------------------------------------------------------------------------------------------------------
2009............................................ n/a 0.5 0.6 11.1
2010............................................ 0.1 0.65 0.95 12.95
2011............................................ 0.25 0.80 1.35 13.95
2012............................................ 0.5 1.0 2.0 15.2
2013............................................ 1.0 \a\ 2.75 16.55
2014............................................ 1.75 \a\ 3.75 18.15
2015............................................ 3.0 \a\ 5.5 20.5
2016............................................ 4.25 \a\ 7.25 22.25
2017............................................ 5.5 \a\ 9.0 24.0
2018............................................ 7.0 \a\ 11.0 26.0
2019............................................ 8.5 \a\ 13.0 28.0
2020............................................ 10.5 \a\ 15.0 30.0
2021............................................ 13.5 \a\ 18.0 33.0
2022............................................ 16.0 \a\ 21.0 36.0
2023+........................................... \b\ \b\ \b\ \b\
----------------------------------------------------------------------------------------------------------------
\a\ To be determined by EPA through a future rulemaking, but no less than 1.0 billion gallons.
\b\ To be determined by EPA through a future rulemaking.
As shown in the table, the volume requirements are not exclusive, and
generally result in nested requirements. Any renewable fuel that meets
the requirement for cellulosic biofuel or biomass-based diesel is also
valid for meeting the advanced biofuel requirement. Likewise, any
renewable fuel that meets the requirement for advanced biofuel is also
valid for meeting the total renewable fuel requirement. See Section
VI.E for further discussion of which specific types of fuel meet the
requirements for one of the four categories shown in Table II.A.1-1.
We are co-proposing and taking comment on two options for how to
treat the volumes of different renewable fuels for purposes of
complying with the volume mandates of RFS2: As either ethanol-
equivalent gallons, based on energy content, as finalized in the RFS1
program, or as actual volume in gallons. Consideration of the actual
volume option would recognize that EISA now guarantees a market for
specific categories of renewable fuel and assigns a GHG requirement to
each category in the form of minimum GHG thresholds that each must
meet. The approach taken in RFS1 would continue to assign value, in
terms of gallons, to all renewable fuels based on their energy value in
comparison with ethanol. Further discussion of the rationale and
implications of these two approaches can be found in Section III.D.1.
The statutorily-prescribed phase-in period ends in 2012 for
biomass-based diesel and in 2022 for cellulosic biofuel, advanced
biofuel, and total renewable fuel. Beyond these years, EISA requires
EPA to determine the applicable
[[Page 24911]]
volumes based on a review of the implementation of the program up to
that time, and an analysis of a wide variety of factors such as the
impact of the production of renewable fuels on the environment, energy
security, infrastructure, costs, and other factors. For these future
standards, EPA must promulgate rules establishing the applicable
volumes no later than 14 months before the first year for which such
applicable volumes would apply. For biomass-based diesel, this would
mean that final rules would need to be issued by October 31, 2011 for
application starting on January 1, 2013. In today's proposed
rulemaking, we are not suggesting any specific volume requirements for
biomass-based diesel for 2013 and beyond that would be appropriate
under the statutory criteria that we must consider. Likewise, we are
not suggesting any specific volume requirements for the other three
renewable fuel categories for 2023 and beyond. However, the statute
requires that the biomass-based diesel volume in 2013 and beyond must
be no less than 1.0 billion gallons, and that advanced biofuels in 2023
and beyond must represent at a minimum the same percentage of total
renewable fuel as it does in 2022.
2. Changes in How Renewable Fuel Is Defined
Under the existing Renewable Fuel Standard, (RFS1) renewable fuel
is defined generally as ``any motor vehicle fuel that is used to
replace or reduce the quantity of fossil fuel present in a fuel mixture
used to fuel a motor vehicle''. The RFS1 definition includes motor
vehicle fuels produced from biomass material such as grain, starch,
fats, greases, oils and biogas.
The definitions of renewable fuels under today's proposed rule
(RFS2) are based on the new statutory definitions in EISA. Like the
existing rules, the definitions in RFS2 include a general definition of
renewable fuel, but unlike RFS1, we are including a separate definition
of ``Renewable Biomass'' which identifies the feedstocks from which
renewable fuels may be made.
Another difference in the definitions of renewable fuel is that
RFS2 contains three subcategories of renewable fuels: (1) Advanced
Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel.
``Advanced Biofuel'' is a renewable fuel other than ethanol derived
from corn starch and which must achieve a lifecycle GHG emission
displacement of 50%, compared to the gasoline or diesel fuel it
displaces.
Cellulosic biofuel is any renewable fuel, not necessarily ethanol,
derived from any cellulose, hemicellulose, or lignin each of which must
originate from renewable biomass. It must achieve a lifecycle GHG
emission displacement of 60%, compared to the gasoline or diesel fuel
it displaces for it to qualify as cellulosic biofuel.
The RFS1 definition provided that ethanol made at any facility--
regardless of whether cellulosic feedstock is used or not--may be
defined as cellulosic if at such facility ``animal wastes or other
waste materials are digested or otherwise used to displace 90% or more
of the fossil fuel normally used in the production of ethanol.'' This
provision was not included in EISA, and therefore does not appear in
the definitions pertaining to cellulosic biofuel in today's proposed
rule.
The statutory definition of ``renewable biomass'' in EISA does not
include a reference to municipal solid waste (MSW) as did the
definition of ``cellulosic biomass ethanol'' in EPAct, but instead
includes ``separated yard waste and food waste. EPA's proposed
definition of renewable biomass in today's proposed rule includes the
language present in EISA. As discussed in Section III.B.1.a, we invite
comment on whether this definition should be interpreted as including
or excluding MSW containing yard and/or food waste from the definition
of renewable biomass. EPA intends to resolve this matter in the final
rule, and EPA solicits comment on the approach that it should take.
Under today's proposed rule ``Biomass-based diesel'' includes
biodiesel (mono-alkyl esters), non-ester renewable diesel and any other
diesel fuel made from renewable biomass, as long as they are not ``co-
processed'' with petroleum. EISA requires that such fuel achieve a
lifecycle GHG emission displacement of 50%, compared to the gasoline or
diesel fuel it displaces. As discussed in Section III.B.1.d, we are
proposing that co-processing is considered to occur only if both
petroleum and biomass feedstock are processed in the same unit
simultaneously. Thus, if serial batch processing in which 100%
vegetable oil is processed one day/week/month and 100% petroleum the
next day/week/month occurs, the fuel derived from renewable biomass
would be assigned RINs with a D code identifying it as biomass-based
diesel. The resulting products could be blended together, but only the
volume produced from renewable biomass would count as biomass-based
diesel.
For other renewable fuels, EISA makes a distinction between fuel
from new and existing facilities. Only renewable fuel from new
facilities is required to achieve a lifecycle GHG emission displacement
of 20%. As discussed in Section III.B.3, this requirement applies only
to renewable fuel that is produced from certain facilities which
commenced construction after December 19, 2007.
EISA defines ``additional renewable fuel'' as fuel produced from
renewable biomass that is used to replace or reduce fossil fuels used
in home heating oil or jet fuel. The Act provides that EPA may allow
for the generation of RFS credits for such fuel. This represents a
change from RFS1, where renewable fuel qualifying for credits was
limited to fuel used in motor vehicles. We propose to modify the
regulatory requirements to allow RINs assigned to renewable fuel
blended into heating oil or jet fuel to be valid for compliance
purposes. The fuel would still have to meet all the other criteria to
qualify as a renewable fuel, including being made from renewable
biomass. For example, RINs generated for advanced biofuel or biomass-
based diesel that could be used in automobiles would still be valid,
and would not need to be retired, if the fuel producer instead sells
the fuels for use in heating oil or jet fuel.
``Renewable biomass'' is defined in EISA to include a number of
feedstock types, such as planted crops and crop residue, planted trees
and tree residue, animal waste, algae, and yard and food waste.
However, the EISA definition limits many of these feedstocks according
to the management practices for the land from which they are derived.
For example, planted crops and crop residue must be harvested from
agricultural land cleared or cultivated at any time prior to December
19, 2007, that is actively managed or fallow, and non-forested.
Therefore, planted crops and crop residue derived from land that does
not meet this definition cannot be used to produce renewable fuel for
credit under RFS2.
Under today's proposed rule, we describe several options for
ensuring that feedstocks used to produce renewable fuel for which
credits are generated under RFS2 meet the definition of renewable
biomass. Our proposed approach places overall responsibility for
verifying a feedstock's source on the party who generates a RIN for the
renewable fuel produced from the feedstock. We also present options for
how a party could or should verify his or her feedstock, and we seek
comment on these options. A full discussion of the definition and
implementation options for ``renewable biomass'' is presented in
Section III.B.4.
[[Page 24912]]
3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds for
Renewable Fuels
As shown in Table II.A.3-1, EISA requires that a renewable fuel
must meet minimum thresholds for their reduction in lifecycle
greenhouse gas emissions: A 20% reduction in lifecycle GHG emissions
for any renewable fuel produced at new facilities; a 50% reduction in
order to be classified as biomass-based diesel or advanced biofuel; and
a 60% reduction in order to be classified as cellulosic biofuel. The
lifecycle GHG emissions means the aggregate quantity of GHG emissions
related to the full fuel cycle, including all stages of fuel and
feedstock production and distribution, from feedstock generation or
extraction through distribution and delivery and use of the finished
fuel. As mandated by EISA, it includes direct emissions and significant
indirect emissions such as significant emissions from land use changes.
EPA believes that compliance with the EISA mandate--determining the
aggregate GHG emissions related to the full fuel lifecycle, including
both direct emissions and significant indirect emissions such as land
use changes--make it necessary to assess those direct and indirect
impacts that occur not just within the United States but also those
that occur in other countries. This applies to determining the
lifecycle emissions for petroleum-based fuels to determine the
baseline, as well as the lifecycle emissions for biofuels. For
biofuels, this includes evaluating significant emissions from indirect
land use changes that occur in other countries as a result of the
increased domestic production or importation of biofuels into the U.S.
As detailed in Section VI, we have included the GHG emission impacts of
international land use changes including the indirect land use changes
that result from domestic production of biofuel feedstocks. We
recognize the significance of including international land use emission
impacts and, in our analysis presentation in Section VI, have been
transparent in breaking out the various sources of GHG emissions so
that the reader can readily see the impact of including international
land use impacts.
Table II.A.3-1--Lifecycle GHG Thresholds Specified in EISA
[Percent reduction from baseline]
------------------------------------------------------------------------
------------------------------------------------------------------------
Renewable fuel \a\............................................. 20
Advanced biofuel............................................... 50
Biomass-based diesel........................................... 50
Cellulosic biofuel............................................. 60
------------------------------------------------------------------------
\a\ The 20% criterion generally applies to renewable fuel from new
facilities that commenced construction after December 19, 2007.
The lifecycle GHG emissions of the renewable fuel are compared to
the lifecycle GHG emissions for gasoline or diesel (whichever is being
replaced by the renewable fuel) sold or distributed as transportation
fuel in 2005. EISA provides some limited flexibility for EPA to adjust
these GHG percentage thresholds downward by up to 10 percent under
certain circumstances. As discussed in Section VI.D, we are proposing
that the GHG threshold for advanced biofuels be adjusted to 44% or
potentially as low as 40% depending on the results from the analyses
that will be conducted for the final rule. This adjustment would allow
ethanol produced from sugarcane to count as advanced biofuel and would
help ensure that the volume mandate for advanced biofuel could be met.
The regulatory purpose of the lifecycle greenhouse gas emissions
analysis is to determine whether renewable fuels meet the GHG
thresholds for the different categories of renewable fuel. As described
in detail in Section VI, EPA has analyzed the lifecycle GHG impacts of
the range of biofuels currently expected to contribute significantly to
meeting the volume mandates of EISA through 2022. In these analyses we
have used the best science available. Our analysis relies on peer
reviewed models and the best estimate of important trends in
agricultural practices and fuel production technologies as these may
impact our prediction of individual biofuel GHG performance through
2022. We have identified and highlighted assumptions and model inputs
that particularly influence our assessment and seek comment on these
assumptions, the models we have used and our overall methodology so as
to assure the most robust assessment of lifecycle GHG performance for
the final rule.
In addition to the many technical issues addressed in this
proposal, Section VI discusses the emissions decreases and increases
associated with the different parts of the lifecycle emissions of
various biofuels and the timeframes in which these emissions changes
occur. The need to determine a single lifecycle value that best
represents this combination of emissions increases and decreases
occurring over time led EPA to consider various alternative ways to
analyze the timeframe of emissions changes related to biofuel
production and use as well as options for adjusting or discounting
these emissions to determine their net present value. Section VI
highlights two options. One option assumes a 30 year time period for
assessing future GHG emissions impacts of the anticipated increase in
biofuel production to meet the mandates of EISA, both emissions
increases and decreases, and values all these emission impacts the same
regardless of when they occur during that time period (i.e., no
discounting). The second option assesses emissions impacts over a 100
year time period but then discounts future emissions 2% annually to
arrive at an estimate of a net present value of those emissions.
Several other variations of time period and discount rate are also
discussed. The analytical time horizon and the choice whether to
discount GHG emissions and, if so, at what appropriate rate can have a
significant impact on the final assessment of the lifecycle GHG
emissions impacts of individual biofuels as well as the overall GHG
impacts of these EISA provisions and this rule.
We believe that our lifecycle analysis is based on the best
available science and recognize that in some aspects it represents a
cutting edge approach to addressing lifecycle GHG emissions. Because of
the varying degrees of uncertainty in the different aspects of our
analysis, we conducted a number of sensitivity analyses which focus on
key parameters and demonstrate how our assessments might change under
alternative assumptions. By focusing attention on these key parameters,
the comments we receive as well as additional investigation and
analysis by EPA will allow narrowing of uncertainty concerns for the
final rule. In addition to this sensitivity analysis approach, we will
also explore options for more formal uncertainty analyses for the final
rule to the extent possible.
Because lifecycle analysis is a new part of the RFS program, in
addition to the formal comment period on the proposed rule, EPA is
making multiple efforts to solicit public and expert feedback on our
proposed approach. EPA plans to hold a public workshop focused
specifically on lifecycle analysis during the comment period to assure
full understanding of the analyses conducted, the issues addressed and
the options that are discussed. We expect that this workshop will help
ensure that we receive submission of the most
[[Page 24913]]
thoughtful and useful comments to this proposal and that the best
methodology and assumptions are used for calculating GHG emissions
impacts of fuels for the final rule. Additionally, between this
proposal and the final rule, we will conduct peer reviews of key
components of our analysis. As explained in more detail in Section VI,
EPA is specifically seeking peer review of: Our use of satellite data
to project future types of land use changes; the land conversion GHG
emissions factors estimates we have used for different types of land
use; our estimates of GHG emissions from foreign crop production;
methods to account for the variable timing of GHG emissions; and how
the several models we have relied upon are used together to provide
overall lifecycle GHG estimates.
Some renewable fuel is not required to meet the 20% GHG threshold.
Section 211(o)(2)(A) provides that only renewable fuel produced from
new facilities which commenced construction after December 19, 2007
must meet the 20% threshold. Facilities that commenced construction on
or before December 19, 2007 are exempt or ``grandfathered'' from the
20% threshold requirement. In addition, section 210(a) of EISA provides
a further exemption from the 20% threshold requirement for ethanol
plants that commenced construction in 2008 or 2009 and are fired with
natural gas, biomass, or any combination thereof. The renewable fuel
from such facilities is deemed to be in compliance with the 20%
threshold, and would thus also be ``grandfathered.''
We are proposing and taking comment on one approach to the
grandfathering provisions in today's rule, and seeking comment on five
additional options. The proposed approach would provide an indefinite
time period for grandfathering status but with restrictions to the
baseline volume of renewable fuel that is grandfathered. The
alternative options are (1) Expiration of exemption for grandfathered
status when facilities undergo sufficient changes to be considered
``reconstructed''; (2) Expiration of exemption 15 years after EISA
enactment, industry-wide; (3) Expiration of exemption 15 years after
EISA enactment with limitation of exemption to baseline volume; (4)
``Significant'' production components are treated as facilities and
grandfathered or deemed compliant status ends when they are replaced;
and (5) Indefinite exemption and no limitations placed on baseline
volumes. Our proposal and the alternative options are discussed in
further detail in Section III.B.3.c.
While renewable fuels would be required to meet the GHG thresholds
shown in Table II.A.3-1 in order to be valid for compliance purposes
under the RFS2 program, we are not proposing that an individual
facility-specific lifecycle GHG emissions value would have to be
determined in order to show that the biofuel produced or imported at an
individual facility complies with the threshold. Instead, EPA has
determined lifecycle GHG values for specific combinations of fuel type,
feedstock, and production process, using average values for various
lifecycle model inputs. As a result of these assessments, we propose to
assign each combination of fuel type, feedstock, and production process
to one of the four renewable fuel categories specified in EISA or,
alternatively, make a determination that the biofuel combination has
been disqualified from generating RINs (except as may be allowed for
grandfathered renewable fuel) due to a failure to meet the minimum 20%
GHG threshold. Section VI.E discusses our proposed assignments. We are
also proposing a mechanism to allow biofuels whose lifecycle GHG
emissions have not been assessed to participate in the RFS program
under certain limited conditions. These conditions are described in
Section III.D.5.
4. Coverage Expanded to Transportation Fuel, Including Diesel and
Nonroad Fuels
EPAct only mandated the blending of renewable fuels into gasoline,
though it gave credit for renewable fuels blended into diesel fuel.
EISA expanded the program to generally cover transportation fuel, which
is defined as fuel for use in motor vehicles, motor vehicle engines,
nonroad vehicles, or nonroad engines. This includes diesel fuel
intended for use in highway vehicles and engines, and nonroad,
locomotive, and marine engines and vessels, as well as gaseous or other
fuels used in these vehicles, engines, or vessels. EISA also specifies
that ``transportation fuels'' do not include fuels for use in ocean-
going vessels.
EPA is required to ensure that transportation fuel contains at
least the specified volumes of renewable fuel. Under EISA, renewable
fuel now includes fuel that is used to displace fossil fuel present in
transportation fuel, and as in RFS1, EPA is required to determine the
refiners, blenders, and importers of transportation fuel that are
subject to the renewable volume obligation. As discussed in Section
III.F, while we are seeking comment on alternatives, EPA is proposing
consistent with RFS1 that these provisions could best be met by
requiring that the renewable volume obligation apply to refiners,
blenders, and importers of motor vehicle or nonroad gasoline or diesel
(with limited flexibilities for small refineries and small refiners),
and that their percentage obligation would apply to the amount of
gasoline or diesel they produce for such use. We propose to use the
current definition of motor vehicle, nonroad, locomotive, and marine
diesel fuel (MVNRLM)--as defined at Sec. 80.2(qqq)--to determine the
obligated volumes of non-gasoline transportation fuel for this rule.
We request comment on these aspects of our proposed program.
5. Effective Date for New Requirements
Under CAA section 211(o) as modified by EISA, EPA is required to
revise the RFS1 regulations within one year of enactment, or December
19, 2008. Promulgation by this date would have been consistent with the
revised volume requirements shown in Table II.A.1-1 that begin in 2009
for certain categories of renewable fuel. However, due to the addition
of complex lifecycle assessments to the determination of eligibility of
renewable fuels, the extensive analysis of impacts that we are
conducting for the higher renewable fuel volumes, the various complex
changes to the regulatory program that require close collaboration with
stakeholders, and various statutory limitations such as the Small
Business Regulatory Enforcement Flexibility Act (SBREFA) and a 60 day
Congressional review period for all significant actions, we were not
able to promulgate final RFS2 program requirements by December 19,
2008. As a result, we are proposing that the RFS2 regulatory program go
into effect on January 1, 2010.
In order to successfully implement the RFS2 program, parties that
generate RINs, own and/or transfer them, or use them for compliance
purposes will need to re-register under the RFS2 provisions and modify
their information technology (IT) systems to accommodate the changes we
are proposing today. As described more fully in Section III, these
changes would include redefining the D code within the RIN, adding a
process for verifying that feedstocks meet the renewable biomass
definition, and calculating compliance with four standards instead of
one. Regulated parties will need to establish new contractual
relationships to cover the different types of renewable fuel required
under RFS2. Parties that
[[Page 24914]]
produce MVNRLM diesel but not gasoline will be newly obligated parties
and may be establishing IT systems for the RFS program for the first
time. For RFS1, regulated parties had four months between promulgation
of the final rulemaking on May 1, 2007 and the start of the program on
September 1, 2007. However, this was for a new program that had not
existed before. For the RFS2 program, most regulated parties will
already be familiar with the general requirements for RIN generation,
transfer, and use, and the attendant recordkeeping and reporting
requirements. We believe that with proper attention to the
implementation requirements by regulated parties, the RFS2 program can
be implemented on January 1, 2010 following release of the final rule.
Although we are proposing that the RFS2 regulatory program begin on
January 1, 2010, we seek comment on whether a start date later than
January 1, 2010 would be necessary. Alternative effective dates for the
RFS2 program include January 1, 2011 and a date after January 1, 2010
but before January 1, 2011. We are requesting comment on all issues
related to such an alternative effective date, including the need for
such a delayed start, treatment of diesel producers and importers,
whether the standards for advanced biofuel, cellulosic biofuel and
biomass-based diesel should apply to the entire 2010 production or just
the production that would occur after the RFS2 effective date, and the
extent to which RFS1 RINs should be valid to show compliance with RFS2
standards. Further discussion of alternative effective dates for RFS2
can be found in Section III.E.1.d.
6. Treatment of Required Volumes Preceding the RFS2 Effective Date
We are proposing that the RFS2 regulatory program begin on January
1, 2010. Under CAA section 211(o), the requirements for refiners,
blenders, and importers (called ``obligated parties'') as well as the
requirements for producers of renewable fuel and others, stem from the
regulatory provisions adopted by EPA. In effect while EPAct and EISA
both call for EPA to issue regulations that achieve certain results,
the various regulated parties are not subject to these requirements
until EPA issues the regulations establishing their obligations. The
changes brought about by EISA, such as the 4 separate standards, the
lifecycle GHG thresholds, changes to obligated parties, and the revised
definition of renewable biomass do not become effective until today's
proposal is finalized. Rather, the current RFS1 regulations continue to
apply until EPA amends them to implement EISA, and any delay in
issuance of the RFS2 regulations means that parties would continue to
be subject to the RFS1 regulations until the RFS2 regulations were in
effect. Therefore, regulated parties would continue to be subject to
the existing regulations at 40 CFR Part 80 Subpart K through December
31, 2009, or later if the effective date of the RFS2 program were later
than January 1, 2010.
Under the RFS1 regulations the annual percentage standards that are
applicable to obligated parties are determined by a formula set forth
in the regulations. The formula uses gasoline volume projections from
the Energy Information Administration (EIA) and the required volume of
renewable fuel provided in Clean Air Act section 211(o)(2)(B). Since
EISA modified the required volumes in this section of the Clean Air
Act, EPA believes that the new statutory volumes can be used under the
RFS1 regulations in generating the standards for 2009. Therefore, in
November 2008 we used the new total renewable fuel volume of 11.1
billion gallons as the basis for the 2009 standard, and not the 6.1
billion gallons that was required by EPAct.\3\
---------------------------------------------------------------------------
\3\ 73 FR 70643, November 21, 2008.
---------------------------------------------------------------------------
While this approach will ensure that the total renewable fuel
volume of 11.1 billion gallons required by EISA for 2009 will be used,
the RFS1 regulatory structure does not provide a mechanism for
implementing the 0.5 billion gallon requirement for biomass-based
diesel nor the 0.6 billion gallon requirement for advanced biofuel. As
described in more detail in Section III.E.2, we are proposing to
address this issue by increasing the 2010 biomass-based diesel
requirement by 0.5 billion gallons and allowing 2009 biodiesel and
renewable diesel RINs to be used to meet this combined 2009/2010
requirement. Doing so would also allow most of the 2009 advanced
biofuel requirement to be met. We believe this would provide a similar
incentive for biomass-based diesel use in 2009 as would have occurred
had we been able to implement this standard for 2009. We propose that
this requirement would apply to all obligated parties under RFS2,
including producers and importers of diesel fuel.
As noted above, EPA is proposing a start date for the RFS2 program
of January 1, 2010, and is also seeking comment on alternative start
dates of sometime during 2010 or January 1, 2011. If the start date is
other than January 1, 2010, EPA would need to determine what renewable
fuel volumes to require in the interim between January 1, 2010 and the
start of the RFS2 program. While we could apply the same approach,
described above, that we have used for 2009, doing so could mean that
2009 biodiesel RINs would be valid for compliance purposes in 2011,
which would run counter to the statutory valid life of two years.
Nevertheless, we request comment on whether this potential approach or
another approach is warranted based on the differing volumes and types
of renewable fuel specified for use in EISA for 2010.
7. Waivers and Credits for Cellulosic Biofuel
Section 202(e) of EISA provides that for any calendar year in which
the projected volume of cellulosic biofuel production is less than the
minimum applicable volume required by the statute, EPA will waive a
portion of the cellulosic biofuel standard by using the projected
volume as the basis for setting the applicable standard. In this event,
EISA also allows but does not require EPA to reduce the required volume
of advanced biofuel and total renewable fuel. The process of projecting
the volume of cellulosic biofuel that may be produced in the next year,
and the associated process of determining whether and to what degree
the advanced biofuel and total renewable fuel requirements should be
lowered, will involve considerations that extend beyond the simple
calculation based on gasoline demand that was used to set the annual
standards under RFS1. As a result, we believe that this process should
be subject to a notice-and-comment rulemaking process. Moreover, since
we must make these determinations every year for application to the
following year, we expect to conduct these rulemakings every year.
In determining whether the advanced biofuel and/or total renewable
fuel volume requirements should also be adjusted downward in the event
that projected volumes of cellulosic biofuel fall short of the
statutorily required volumes, we believe it would be appropriate to
allow excess advanced biofuels to make up some or all of the shortfall
in cellulosic biofuel. For instance, if we determined that sufficient
biomass-based diesel was available, we could decide that the required
volume of advanced biofuel need not be lowered, or that it should be
lowered to a smaller degree than the required cellulosic biofuel
volume. We would then lower the total renewable fuel volume to the same
degree that we
[[Page 24915]]
would lower the advanced biofuel volume. We do not believe it would be
appropriate to lower the advanced biofuel standard but not the total
renewable standard, as this would allow conventional biofuels to
effectively be used to meet the standards Congress specifically set for
cellulosic and advanced biofuels.
If EPA reduces the required volume of cellulosic biofuel, EPA must
offer a number of credits no greater than the reduced cellulosic
biofuel standard. EISA dictates the cost of these credits and ties them
to inflation. The Act also dictates that we must promulgate regulations
on the use of these credits and offers guidance on how these credits
may be offered and used. We propose that their uses will be very
limited. The credits would not be allowed to be traded or banked for
future use, but would be allowed to meet the cellulosic biofuel
standard, advanced biofuel standard and total renewable fuel standard.
Further discussion of the implementation of these provisions can be
found in Section III.I.
8. Proposed Standards for 2010
Once the RFS2 program is implemented, we expect to conduct a
notice-and-comment rulemaking process each year in order to determine
the appropriate standards applicable in the following year. We
therefore intend to issue an NPRM in the spring and a final rule by
November 30 of each year as required by statute.
However, for the 2010 compliance year, today's action provides a
means for seeking comment on the applicable standards. Therefore,
rather than issuing a separate NPRM for the 2010 standard, we are
proposing the 2010 standards in today's notice. We will consider
comments received during the comment period associated with today's
NPRM, and we expect to issue a Federal Register notice by November 30,
2009 setting the applicable standards for 2010.
We propose that the RFS2 program be effective on January 1, 2010.
Therefore, all EISA volume mandates for 2010 would be implemented in
that year, unless EPA exercised its authority to waive one or more of
the standards. Based on information from the industry, we believe that
there are sufficient plans underway to build plants capable of
producing 0.1 billion gallons of cellulosic biofuel in 2010, the
minimum volume of cellulosic biofuel required by EISA for 2010.
However, we recognize that cellulosic biofuel is at the very earliest
stages of commercialization and current economic concerns could have
significant impacts on these near term plans. Therefore, while based on
industry plans available to EPA, we are not proposing that any portion
of the cellulosic biofuel requirement for 2010 be waived, we are
seeking additional and updated information that would be available
prior to November 30, 2009 which could result in a change in this
conclusion. Similarly, we are not aware of the need to waive any other
volume mandates for 2010. Therefore, we are proposing that the volumes
shown in Table II.A.1-1 for all four renewable fuel categories be used
as the basis for the applicable standards for 2010. The proposed
standards are shown in Table II.A.8-1, each representing the fraction
of a refiner's or importer's gasoline and diesel volume which must be
renewable fuel.
Table II.A.8-1--Proposed Standards for 2010
[Percent]
------------------------------------------------------------------------
------------------------------------------------------------------------
Cellulosic biofuel............................................. 0.06
Biomass-based diesel........................................... 0.71
Advanced biofuel............................................... 0.59
Renewable fuel................................................. 8.01
------------------------------------------------------------------------
Note that the proposed 2010 standards shown in Table II.A.8-1 were
based on currently available projections of 2010 gasoline and diesel
volumes. The final standards will be calculated on the basis of
gasoline and diesel volume projections from the Energy Information
Administration's (EIA) Short-Term Energy Outlook and published by
November 30, 2009. Additional discussion of our proposed 2010 standards
can be found in Section III.E.1.b.
Note also that the proposed standards assume an effective date of
January 1, 2010 for RFS2. We are taking comment on alternative
effective dates for RFS2, including January 1, 2011 and a date after
January 1, 2010 but before January 1, 2011. Such alternative effective
dates would raise issues with regard to the calculation and application
of the standards for total renewable fuel and the other standards
required under EISA, as well as the generation and application of RINs
under RFS1 and RFS2. As described more fully in Section III.E.1.d, we
request comment on the issues associated with alternative effective
dates for RFS2.
B. Impacts of Increasing Volume Requirements in the RFS2 Program
The displacement of gasoline and diesel with renewable fuels has a
wide range of environmental and economic impacts. As we describe below,
we have assessed many of these impacts for the RFS2 proposal and we
will have more complete assessments, including a cost-benefit
comparison, for the final rule. These assessments provide important
information to the wider public policy considerations of renewable
fuels, climate change, and national energy security. They are also an
important component of all significant rulemakings.
However, because the volumes of renewable fuel were specified by
statute, they would not be based on or revised by our analysis of
impacts. In addition, because we have very limited discretion to pursue
regulatory alternatives, the proposal does not include a systematic
alternatives analysis. We have investigated regulatory alternatives in
some areas to the degree that EISA provides discretion.
As one point of reference to assess the impacts of the volume
requirements for the RFS2 program, we used projections for renewable
fuel use in 2022 that EIA issued through their 2007 Annual Energy
Outlook (AEO), and for transportation fuel consumption through their
2008 AEO. This reference case, referred to as the ``AEO Reference
Case,'' represents a projection of the demand for renewable fuels prior
to enactment of EISA while still reflecting the new Corporate Average
Fuel Economy (CAFE) requirements in EISA, and the 2008 AEO projections
for the future price of crude oil ($53 to $92 per barrel). Further
discussion of the Reference Case can be found in Section V.A.1. Other
points of reference include the renewable fuel volumes mandated by
EPAct for the RFS1 program, renewable fuel use prior to implementation
of the RFS1 program, and the full impacts of renewable fuel use
compared to a petroleum-only economy.
Given the short time provided by Congress to conduct a rulemaking,
many of our analyses were done in parallel for this proposal. As a
result, some analyses were conducted without the benefit of waiting for
the conclusion of another analysis that could prove influential. Thus,
for example, impacts on food prices assume that soy-based biodiesel and
sugarcane ethanol will qualify as advanced fuels under the proposed
RFS2 program, even though the analyses conducted for this proposal
might preclude such eligibility. We have highlighted such
inconsistencies in results and assumptions throughout the proposal.
Additionally, since we have identified many issues and analytical
options in our assessment of which biofuel pathways would comply with
the GHG thresholds, the assessment we
[[Page 24916]]
conducted for this proposal may not reflect the final rule in all
cases. We will be addressing these issues of analytical consistency
between analyses more fully in the final rule.
In a similar fashion, while we recognize uncertainty in our
assessment of impacts of the proposed RFS2 program, we do not present a
formal, comprehensive analysis of uncertainty. For this proposal, many
of the analyses are without precedent, and as a result we have
identified the more uncertain aspects of these analyses and have worked
to assess their potential impact on the results through sensitivity
analyses. We intend to continue these assessments for the final rule,
and expect that comments on this proposal will allow us to reduce our
uncertainty in a number of areas. In addition to this sensitivity
analysis approach, we will also explore options for more formal
uncertainty analyses for the final rule to the extent possible.
1. Greenhouse Gases and Fossil Fuel Consumption
Our analyses of GHG impacts consider the full useful life
assessment of the production of biofuels compared to the petroleum-
based fuels they would replace. The analysis compared the AEO reference
case transportation fuel pool in 2022 without the EISA mandates with
the same fuel pool in 2022, but assuming the greater volumes of biofuel
as mandated by EISA replace an energy equivalent amount of petroleum-
based fuel. The incremental volumes of each biofuel type were then
evaluated to determine their average impact on GHG emissions compared
to the 2005 baseline petroleum fuel they would be displacing. These
average GHG emission reduction results can then be compared to the
threshold performance levels for each fuel type.
As a result of the transition to greater renewable fuel use, some
petroleum-based gasoline and diesel will be directly replaced by
renewable fuels. Therefore, consumption of petroleum-based fuels will
be lower than it would be if no renewable fuels were used in
transportation vehicles. However, a true measure of the impact of
greater use of renewable fuels on petroleum use, and indeed on the use
of all fossil fuels, accounts not only for the direct use and
combustion of the finished fuel in a vehicle or engine, but also
includes the petroleum use associated with production and
transportation of that fuel. For instance, fossil fuels are used in
producing and transporting renewable feedstocks such as plants or
animal byproducts, in converting the renewable feedstocks into
renewable fuel, and in transporting and blending the renewable fuels
for consumption as motor vehicle fuel. Likewise, fossil fuels are used
in the production and transportation of petroleum and its finished
products. In order to estimate the true impacts of increases in
renewable fuel use on fossil fuel use, we must take these steps into
account. Such analyses are termed lifecycle analyses.
The definition of lifecycle greenhouse gas emissions in EISA
requires the Agency to look broadly at lifecycle analyses and to
develop a methodology that accounts for the significant secondary or
indirect impacts of expanded biofuels use. These indirect effects
include both the domestic and international impact of land use change
from increased biofuel feedstock production and the secondary
agricultural sector GHG impacts from increased biofuel feedstock
production (e.g., changes in livestock emissions due to changes in
agricultural commodity prices). Today no single model can capture all
of the complex interactions required to conduct a complete lifecycle
assessment as required by Congress. As a result, the methodology EPA
has currently evaluated uses a number of models and tools to provide a
comprehensive estimate of GHG emissions. We have used a combination of
peer reviewed models including Argonne National Laboratory's GREET
model, Texas A&M's Forestry and Agricultural Sector Optimization Model
(FASOM) and Iowa State University's Food and Agricultural Policy
Research Institute's (FAPRI) international agricultural models as well
as the Winrock International database to estimate lifecycle GHG
emissions estimates. These models are described in more detail in
Section VI and have been used in combination to provide the lifecycle
GHG estimates presented in this proposal. However, we recognize other
models and sources of information can also be used and these are also
discussed in Section VI.
Based on the combined use of these models we have estimated the
lifecycle GHG emissions for a number of pathways for producing the
increased volumes of renewable fuels as mandated by EISA. Section VI of
this proposal outlines the approach taken and describes the key
assumptions and parameters used in this analysis. In addition, this
section highlights the impacts of varying these key inputs on the
overall results.
We estimate the greater volumes of biofuel mandated by RFS2 will
reduce lifecycle GHG emissions from transportation by approximately 6.8
billion tons of CO2 equivalent emissions when accounting for
all the emissions changes over 100 years and then discounting this
emission stream by 2% per year. This is equivalent to an average
annualized emission rate of 160 million metric tons of CO2-
eq. emissions per year over the entire 100 year modeling time frame if
that average annualized emission rate is also discounted at 2% per
year. Determining lifecycle GHG emissions values for renewable fuels
using a 0% discount rate over 30 years would result in an estimated
total reduction of 4.5 billion tons of CO2-eq. over the 30
year period or an average annualized emission rate reduction of 150
million metric tons of CO2-eq. GHG emissions per year. (See
Section VI.F of this preamble for additional information on how these
emission reductions were calculated).
Our analysis of the petroleum consumption impacts took a similar
lifecycle approach. For the year 2022, we estimate that the 36 billion
gallons of renewable fuel mandated by these rules will increase
renewable fuel usage by approximately 22 billion gallons which will
displace about 15 billion gallons of petroleum-based gasoline and
diesel fuel. This represents about 8% of annual oil consumed by the
transportation sector in 2022.
2. Economic Impacts and Energy Security
The substantially increased volumes of renewable fuel that would be
required under RFS2 would produce a variety of different economic
impacts. These would include changes in the cost of gasoline and
diesel, a reduction in nationwide expenditures on petroleum imports and
the associated increase in energy security, and increases in the prices
of agricultural commodities such as corn and soybeans.
The RFS program is projected to significantly impact the cost of
gasoline and diesel, though the estimated costs vary based on the price
of crude oil that is assumed. In our analysis we used both $92 and $53
per barrel crude oil based on price projections made by EIA. At these
two crude oil price points, we estimate that gasoline costs would
increase by about 2.7 and 10.9 cents per gallon, respectively, by 2022.
Likewise, diesel fuel costs could experience a small cost reduction of
0.1 cents per gallon, or increase by about 1.2 cent per gallon,
respectively. For the nation as a whole, these costs are equivalent to
$4 and $18 billion in 2022, respectively (in 2006 dollars, and
amortizing capital costs using a 7% before-tax rate of return). These
costs represent the nationwide average impacts including the costs of
producing and distributing
[[Page 24917]]
both renewable fuels and gasoline and diesel, as well as blending
costs, but without consideration of either the tax subsidies and import
tariff for ethanol or tax subsidies for biodiesel and renewable diesel
fuel.
EPA's estimates of economic impacts of fuels do not consider other
societal benefits. For example, the displacement of petroleum-based
fuel (largely imported) by renewable fuel (largely produced in the
United States), should reduce our consumption of imported oil and fuel.
We estimate that 91% of the lifecycle petroleum reductions resulting
from the use of renewable fuel will be met through reductions in net
petroleum imports. In Section IX of this preamble we estimate the value
of the decrease in imported petroleum at about $12.4 billion in 2022
due to increased volumes of renewable fuels mandated by RFS2 in
comparison to the AEO reference case. Net U.S. expenditures on
petroleum imports in 2022 are projected to be about $208 billion.
Furthermore, the above estimate of reduced U.S. petroleum import
expenditures only partly assesses the economic impacts of this
proposal. One of the effects of increased use of renewable fuel is that
it diversifies the energy sources used in making transportation fuel.
To the extent that diverse sources of fuel energy reduce the U.S.
dependence on any one source, the risks, both financial as well as
strategic, of a potential disruption in supply of a particular energy
source are reduced. EPA has worked with researchers at Oak Ridge
National Laboratory (ORNL) to update a study they previously published
that has been used or cited in several government actions impacting
U.S. oil consumption. This updated study went through an independent,
third-party peer review process and a final draft report of this
updated study was developed. This peer-reviewed report is being made
available in the docket at this time for further consideration. Using
the updated ORNL estimate, the total energy security benefits
associated with a reduction of U.S. imported oil is $12.38 per barrel
of imported oil that is reduced. Based on these values, we estimate
that the total annual energy security benefits would be $3.7 billion in
2022 (in 2006 dollars).
We recognize that our current energy security analysis does not
take into account risk-shifting that might occur as the U.S. reduces
its dependency on petroleum by increasing its use of biofuels. For
example, our analysis did not take into account other energy security
implications associated with biofuels, such as possible supply
disruptions of corn-based ethanol. We will attempt to broaden our
energy security analysis to incorporate estimates of overall motor fuel
supply and demand flexibility and reliability for the final rule, along
with impacts of possible agricultural sector market disruptions. A
complete discussion of the Agency's plans for this analysis can be
found in Section IX.B.2. of this preamble.
While increased use of renewable fuel will reduce expenditures on
imported oil, it will also increase expenditures on renewable fuels and
in turn on the sources of those renewable fuels. The RFS program is
likely to spur the increased use of renewable transportation fuels made
principally from agricultural crops and it is expected that most of
these crops will be produced in the U.S. As a result, it is important
to analyze the consequences of the transition to greater renewable fuel
use in the U.S. agricultural sector. To analyze the domestic
agricultural sector impacts, EPA selected the Forest and Agricultural
Sector Optimization Model (FASOM) developed by Professor Bruce McCarl
of Texas A&M University and others over the past thirty years. FASOM is
a dynamic, nonlinear programming model of the agriculture and forestry
sectors of the U.S.
In Section IX of this preamble, we estimate the change in the price
of various agricultural products as a result of this rulemaking. By
2022, we estimate the price of corn would increase by $0.15 per bushel
(4.6%) above the Reference Case price of $3.19 per bushel. By 2022,
U.S. soybean prices would increase by $0.29 per bushel (2.9%) above the
Reference Case price of $9.97 per bushel. Due to higher commodity
prices, FASOM estimates that U.S. food costs would increase by $10 per
person per year by 2022, relative to the Reference Case. Total farm
gate food costs would increase by $3.3 billion (0.2%) in 2022. As a
result of increased renewable fuel requirements, FASOM predicts that
net U.S. farm income would increase by $7.1 billion dollars in 2022
(10.6%), relative to the Reference Case.
Due to higher commodity prices, FASOM estimates that U.S. corn
exports would drop from 2.7 billion bushels under the Reference Case to
2.4 billion bushels (a 10% decrease) by 2022. In value terms, U.S.
exports of corn would fall by $487 million in 2022. FASOM estimates
that U.S. exports of soybeans would decrease from 1.03 billion bushels
to 943 million bushels (an 8% decrease) in 2022. In value terms, U.S.
exports of soybeans would decrease by $691 million in 2022.
Assuming current subsidies remain in place, the Renewable Fuels
Standard, by encouraging the use of biofuels, will result in an
expansion of subsidy payments by the U.S. government. If this resulting
loss of tax revenue were offset by an increase in taxes, this could
have a distortionary impact on the economy. We intend to consider the
impact of the expansion of biofuel subsidies associated with the RFS2
in the context of the economy-wide modeling to be conducted for the
final rule.
We note that the economic analyses that support this proposal do
not reflect all of the potentially quantifiable economic impacts. There
are several key impacts that remain incomplete as a result of time and
resource constraints, including the economic impact analysis (see
Section IX) and the air quality and health impacts analysis (see
Section II.B.3). As a result, this proposal does not combine economic
impacts in an attempt to compare costs and benefits, in order to avoid
presenting an incomplete and potentially misleading characterization.
For the final rule, when the planned analyses are complete and current
analyses updated, we will provide a consistent cost-benefit comparison.
3. Emissions, Air Quality, and Health Impacts
Analysis of criteria and toxic emission impacts was performed
relative to three different reference case ethanol volumes, ranging
from 3.64 to 13.2 billion gallons per year. To assess the total impact
of the RFS program, emissions were analyzed relative to the RFS1 rule
base case of 3.64 billion gallons in 2004. To assess the impact of
today's RFS2 proposal relative to the current mandated volumes, we
analyzed impacts relative to RFS1 mandate of 7.5 billion gallons of
renewable fuel use by 2012, which was estimated to include 6.7 billion
gallons of ethanol.\4\ In order to assess the impact of today's
proposal relative to the level of ethanol projected to be used in 2022
without RFS2, the AEO2007 projection of 13.2 billion gallons of ethanol
in 2022 was analyzed.
---------------------------------------------------------------------------
\4\ RFS1 base and mandated ethanol levels were projected to
remain essentially unchanged in 2022 due to the flat energy demands
projected by EIA.
---------------------------------------------------------------------------
We are also presenting a range of impacts meant to bracket the
impacts of ethanol blends on light-duty vehicle emissions. Similar to
the approach presented in the RFS1 rule, we present a ``less
sensitive'' and ``more sensitive'' case to present a range of the
possible
[[Page 24918]]
emission impacts of E10 on recent model year light duty gasoline
vehicles. As detailed in Section VII.C, ``less sensitive'' does not
apply any E10 effects to NOX or HC emissions for later model
year vehicles, or E85 effects for any pollutant, while ``more
sensitive'' does.
Our projected emission impacts for the ``less sensitive'' and
``more sensitive'' cases are shown in Table II.B.3-1 and II.B.3-2,
showing the expected emission changes for the U.S. in 2022, and the
percent contribution of this impact relative to the total U.S.
inventory across all sectors. Overall we project the proposed program
will result in significant increases in ethanol and acetaldehyde
emissions--increasing the total U.S inventories of these pollutants by
up to 30-40% in 2022 relative to the RFS1 mandate case. We project more
modest but still significant increases in acrolein, NOX,
formaldehyde and PM. We project today's action will result in decreased
ammonia emissions (due to reductions in livestock agricultural
activity), decreased CO emissions (driven primarily by the impacts of
ethanol on exhaust emissions from vehicles and nonroad equipment), and
decreased benzene emissions (due to displacement of gasoline with
ethanol in the fuel pool). Discussion and a breakdown of these results
by the fuel production/distribution and vehicle and equipment emissions
are presented in Section VII.
Table II.B.3-1--RFS2 ``Less Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 mandate AEO2007
-----------------------------------------------------------------------------------------------
Pollutant Annual short % of total Annual short % of total Annual short % of total
tons U.S. inventory tons U.S. inventory tons U.S. inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX..................................................... 312,400 2.8 274,982 2.5 195,735 1.7
HC...................................................... 112,401 1.0 72,362 0.6 -8,193 -0.07
PM10.................................................... 50,305 1.4 37,147 1.0 9,276 0.3
PM2.5................................................... 14,321 0.4 11,452 0.3 5,376 0.16
CO...................................................... -2,344,646 -4.4 -1,669,872 -3.1 -240,943 -0.4
Benzene................................................. -2,791 -1.7 -2,507 -1.5 -1,894 -1.1
Ethanol................................................. 210,680 36.5 169,929 29.4 83,761 14.5
1,3-Butadiene........................................... 344 2.9 255 2.1 65 0.5
Acetaldehyde............................................ 12,516 33.7 10,369 27.9 5,822 15.7
Formaldehyde............................................ 1,647 2.3 1,348 1.9 714 1.0
Naphthalene............................................. 5 0.03 3 0.02 -1 -0.01
Acrolein................................................ 290 5.0 252 4.4 174 3.0
SO2..................................................... 28,770 0.3 4,461 0.05 -47,030 -0.5
NH3..................................................... -27,161 -0.6 -27,161 -0.6 -27,161 -0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table II.B.3-2--RFS2 ``More Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 mandate AEO2007
-----------------------------------------------------------------------------------------------
Pollutant Annual short % of total Annual short % of total Annual short % of total
tons U.S. inventory tons U.S. inventory tons U.S. inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX..................................................... 402,795 3.6 341,028 3.0 210,217 1.9
HC...................................................... 100,313 0.9 63,530 0.6 -15,948 -0.14
PM10.................................................... 46,193 1.3 33,035 0.9 5,164 0.15
PM2.5................................................... 10,535 0.3 7,666 0.2 1,589 0.05
CO...................................................... -3,779,572 -7.0 -3,104,798 -5.8 -1,675,869 -3.1
Benzene................................................. -5,962 -3.5 -5,494 -3.3 -4,489 -2.7
Ethanol................................................. 228,563 39.6 187,926 32.5 105,264 18.2
1,3-Butadiene........................................... -212 -1.8 -282 -2.4 -430 -3.6
Acetaldehyde............................................ 16,375 44.0 14,278 38.4 9,839 26.5
Formaldehyde............................................ 3,373 4.7 3,124 4.3 2,596 3.6
Naphthalene............................................. -175 -1.2 -178 -1.3 -187 -1.3
Acrolein................................................ 253 4.4 218 3.8 143 2.5
SO2..................................................... 28,770 0.3 4,461 0.05 -47,030 -0.5
NH3..................................................... -27,161 -0.6 -27,161 -0.6 -27,161 -0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
We note that the aggregate nationwide emission inventory impacts
presented here will likely lead to health impacts throughout the U.S.
due to changes in future-year ambient air quality. However, emissions
changes alone are not a good indication of local or regional air
quality and health impacts, as there may be highly localized impacts
such as increased emissions from ethanol plants and evaporative
emissions from cars, and decreased emissions from gasoline refineries.
In addition, the atmospheric chemistry related to ambient
concentrations of PM2.5, ozone and air toxics is very
complex, and making predictions based solely on emissions changes is
extremely difficult. Full-scale photochemical modeling is necessary to
provide the needed spatial and temporal detail to more completely and
accurately estimate the changes in ambient levels of these pollutants.
As discussed in Section VII.D, timing and resource constraints
precluded EPA from conducting a full-scale photochemical air quality
modeling analysis in time for the NPRM. For the final rule, however, a
national-scale air quality modeling analysis will be performed to
analyze the impacts of the proposed standards on PM2.5,
ozone, and selected air toxics (i.e., benzene, formaldehyde,
acetaldehyde, ethanol, acrolein and 1,3-butadiene). As described in
Section VII.D.2, EPA intends to use a 2005-based Community Multi-scale
Air Quality (CMAQ) modeling platform as the tool for the air
[[Page 24919]]
quality modeling. The CMAQ modeling system is a comprehensive three-
dimensional grid-based Eulerian air quality model designed to estimate
the formation and fate of oxidant precursors, primary and secondary PM
concentrations and deposition, and air toxics, over regional and urban
spatial scales (e.g., over the contiguous U.S.).
The lack of air quality modeling data also precluded EPA from
conducting its standard analysis of human health impacts, where CMAQ
output data are used as inputs to the Environmental Benefits Mapping
and Analysis Program (BenMAP). Section IX.D of this preamble describes
the human health impacts that will be quantified and monetized for the
final rule, as well as the unquantified impacts that will be
qualitatively described.
4. Water
As the production of biofuels increases to meet the requirements of
this proposed rule, there may be adverse impacts on both water quality
and quantity. Increased production of biofuels may lead to increased
application of fertilizer and pesticides and increased soil erosion,
which could impact water quality. Since ethanol production uses large
quantities of water, the supply of water could also be significantly
impacted in some locations.
EPA focused the water quality analysis for this proposal on the
impacts of corn produced for ethanol for several reasons. Corn has the
highest fertilizer and pesticide use per acre and accounts for the
largest share of nitrogen fertilizer use among all crops. Furthermore,
corn-based ethanol is expected to be a large component of the biofuels
mix.
Fertilizer nutrients that are not used by the crops are available
to runoff to surface water or leach into groundwater. Nutrient
enrichment due to human activities is one of the leading problems
facing our nation's lakes, reservoirs, and estuaries, and also has
negative impacts on aquatic life in streams; adverse health effects on
humans and domestic animals; and impairs aesthetic and recreational
use. Excess nutrients can lead to excessive growth of algae in rivers
and streams, and aquatic plants in all waters. Nutrient pollution is
widespread. The most widely known examples of significant nutrient
impacts include the Gulf of Mexico and the Chesapeake Bay, however
waterbodies in virtually every state and territory are impacted by
nutrient-related degradation. A more detailed discussion of nutrient
pollution can be found in Section X of this preamble and in Chapter 6
of the DRIA.
To provide a quantitative estimate of the impact of this proposal
and production of corn ethanol generally on water quality, EPA
conducted an analysis that modeled the changes in loadings of nitrogen,
phosphorus, and sediment from agricultural production in the Upper
Mississippi River Basin (UMRB). The UMRB is representative of the many
potential issues associated with ethanol production, including its
connection to major water quality concerns such as Gulf of Mexico
hypoxia, large corn acreage, and numerous ethanol production plants.
The UMRB contributes 39% of nitrogen loads and 26% of phosphorus loads
to the Gulf of Mexico.
EPA selected the SWAT (Soil and Water Assessment Tool) model to
assess nutrient loads from changes in agricultural production in the
UMRB. SWAT is a physical process model developed to quantify the impact
of land management practices in large, complex watersheds. In
conducting its analysis EPA quantified the impacts from a baseline that
preceded the current high production of ethanol from corn to four
future years--2010, 2015, 2020 and 2022.
Table II.B.4-1 summarizes the model outputs at the outlet of the
UMRB in the Mississippi River at Grafton, Illinois for each of the four
scenario years. The local impact in smaller watersheds within the UMRB
may be significantly different. The decreasing nitrogen load over time
is likely attributed to the increased corn yield production, resulting
in greater plant uptake of nitrogen. The relatively stable sediment
loadings are likely due to the fact that corn was modeled assuming that
corn stover is left on the fields following harvest.
Table II.B.4-1--Changes From the 2005 Baseline to the Mississippi River at Grafton, Illinois From the Upper
Mississippi River Basin
----------------------------------------------------------------------------------------------------------------
2005 Baseline 2010 2015 2020 2022
----------------------------------------------------------------------------------------------------------------
Average corn yield (bushels/acre)......... 141......................... 150 158 168 171
Nitrogen.................................. 1433.5 million lbs.......... +5.5% +4.7% +2.5% +1.8%
Phosphorus................................ 132.4 million lbs........... +2.8% +1.7% +0.98% +0.8%
Sediment.................................. 6.4 million tons............ +0.5% +0.3% +0.2% +0.1%
----------------------------------------------------------------------------------------------------------------
After evaluating comments on this proposal, if time and resources
permit, EPA may conduct additional water quality analyses using the
SWAT model in the UMRB. Potential future analyses could include: (1)
Determination of the most sensitive assumptions in the model, (2) water
quality impacts from the changes in ethanol volumes between the
reference case and this proposal, (3) removing corn stover for
cellulosic ethanol, and (4) a case study of a smaller watershed to
evaluate local water quality impacts that are impossible to ascertain
at the scale of the UMRB.
EPA also qualitatively examined other water issues, which are also
discussed in detail in Section X of this Preamble, and Chapter 6 of the
DRIA.
5. Agricultural Commodity Prices
The recent increase in food prices, both domestically and
internationally, has raised the issue of whether diverting grains and
oilseeds for fuel production is having a large impact on commodity
markets. While we share the concern that food prices have increased
significantly over the same time period in which renewable fuel
production has increased, many factors have contributed to recent
increases in food prices. As described by the U.S. Department of
Agriculture (USDA), the Department of Energy (DOE), the Council of
Economic Advisors (CEA), and others, the recent increase in commodity
prices has been influenced by factors as diverse as world economic
growth, droughts in Australia, China and Eastern Europe, increasing oil
prices, changes in investment strategies, and the declining value of
the U.S. dollar. While the increase in renewable fuel production has
contributed to the increase in commodity prices, the magnitude of the
contribution of the RFS has most likely been minor, as market
conditions have continued to push renewable fuel use beyond the
mandated levels.
As the mandated levels of renewable fuels continue to rise in the
future, our
[[Page 24920]]
economic modeling suggests that the impact of the RFS2 program on food
prices will continue to be modest, particularly with the expansion of
cellulosic biofuels. Table II.B.5-1 summarizes the changes in prices
for some commodities we have estimated for this proposal. Further
discussion can be found in Section IX.A.
Table II.B.5-1--Change in U.S. Commodity Prices for 2022 in Comparison
to the Reference Case
[2006$]
------------------------------------------------------------------------
------------------------------------------------------------------------
Corn............................... $0.15/bushel.
Soybeans........................... $0.29/bushel.
Sugarcane.......................... $13.34/ton.
Beef............................... $0.93/hundred pounds.
------------------------------------------------------------------------
II. What Are the Major Elements of the Program Required Under EISA?
While EISA made a number of changes to CAA section 211(o) that must
be reflected in the RFS program regulations, it left many of the basic
program elements intact, including the mechanism for translating
national renewable fuel volume requirements into applicable standards
for individual obligated parties, requirements for a credit trading
program, geographic applicability, treatment of small refineries, and
general waiver provisions. As a result, we propose that many of the
regulatory requirements of the RFS1 program would remain largely or, in
some cases, entirely unchanged. These provisions would include the
distribution of RINs, separation of RINs, use of RINs to demonstrate
compliance, provisions for exporters, recordkeeping and reporting,
deficit carryovers, and the valid life of RINs.
The primary elements of the RFS program that we propose changing to
implement the requirements in EISA fall primarily into the following
five areas:
(1) Expansion of the applicable volumes of renewable fuel
(2) Separation of the volume requirements into four separate
categories of renewable fuel, with corresponding changes to the RIN and
to the applicable standards
(3) Changes to the definition of renewable fuels and criteria for
determining which if any of the four renewable fuel categories a given
renewable fuel is eligible to meet
(4) Expansion of the fuels subject to the standards (and applicable
to refiners, blenders, and importers of those fuels) to include diesel
and certain nonroad fuels
(5) Inclusion of specific types of waivers and EPA-generated
credits for cellulosic biofuel.
EISA does not change the basic requirement under CAA 211(o) that
the RFS program include a credit trading program. In the May 1, 2007
final rulemaking implementing the RFS1 program, we described how we
reviewed a variety of approaches to program design in collaboration
with various stakeholders. We finally settled on a RIN-based system for
compliance and credit purposes as the one which met our goals of being
straightforward, maximizing flexibility, ensuring that volumes are
verifiable, and maintaining the existing system of fuel distribution
and blending. RINs represent the basic framework for ensuring that the
statutorily required volumes of renewable fuel are produced and used as
transportation fuel in the U.S. The use of RINs is predicated on the
fact that once renewable fuels are produced or imported, there is very
high confidence that, setting aside exports, all but de minimus
quantities will in fact be used as transportation fuel in the U.S.
Focusing on production of renewable fuel as a surrogate for the later
actual blending and use of such fuel has many benefits as far as
streamlining the RFS program and minimizing the impact that the program
has on the business operations of the regulated industries. Since the
RIN-based system generally has been successful in meeting EPA's goals,
we propose to maintain much of its structure under RFS2.
This section describes the regulatory changes we propose to
implement the new EISA provisions. Section IV describes other changes
to the RFS program that we have considered or are proposing, including
a concept for an EPA-moderated RIN trading system that would provide a
context within which all RIN transfers could occur.
A. Changes to Renewable Identification Numbers (RINs)
Under RFS2, we propose that each RIN would continue to represent
one gallon of renewable fuel for compliance purposes consistent with
our approach under RFS1, and the RIN would continue to have 38 digits.
In general the codes within the RIN would have the same meaning under
RFS2 as they do under RFS1, with the exception of the D code which
would be expanded to cover the four categories of renewable fuel
defined in EISA. The proposed change to the D code is described in
Table III.A-1.
Table III.A-1--Proposed Change to D Code
----------------------------------------------------------------------------------------------------------------
D value Meaning under RFS1 Meaning under RFS2
----------------------------------------------------------------------------------------------------------------
1...................................... Cellulosic biomass ethanol..... Cellulosic biofuel.
2...................................... Any renewable fuel that is not Biomass-based diesel.
cellulosic biomass ethanol.
3...................................... Not applicable................. Advanced biofuel.
4...................................... Not applicable................. Renewable fuel.
----------------------------------------------------------------------------------------------------------------
The determination of which D code would be assigned to a given batch of
renewable fuel is described in more detail in Section III.D.2 below.
As described in Section II.A.5, we are proposing that the RFS2
program go into effect on January 1, 2010. However, we are also taking
comment on other potential start dates including January 1, 2011 and
dates between January 1, 2010 and January 1, 2011. If we were to start
the RFS2 program during 2010 but after January 1, some 2010 RINs would
be generated under the RFS1 requirements and others would be generated
under the RFS2 requirements, but all RINs generated in 2010 would need
to be valid for meeting the appropriate 2010 annual standards. Since
RFS1 RINs and RFS2 RINs would differ in the meaning of the D codes, we
would need a mechanism for distinguishing between these two categories
of RINs in order to appropriately apply them to the standards. One
straightforward way of accomplishing this would be to use values for
the D code under RFS2 that do not overlap the values for the D code
under RFS1. Table III.A-2 describes the D code definitions under such
an alternative approach.
[[Page 24921]]
Table III.A-2--Alternative D Code Definitions
----------------------------------------------------------------------------------------------------------------
D value Meaning under RFS1 Meaning under RFS2
----------------------------------------------------------------------------------------------------------------
1...................................... Cellulosic biomass ethanol..... Not applicable.
2...................................... Any renewable fuel that is not Not applicable.
cellulosic biomass ethanol.
3...................................... Not applicable................. Cellulosic biofuel.
4...................................... Not applicable................. Biomass-based diesel.
5...................................... Not applicable................. Advanced biofuel.
6...................................... Not applicable................. Renewable fuel.
----------------------------------------------------------------------------------------------------------------
In this alternative approach, D code values of 1 and 2 would only
be relevant for RINs generated under RFS1, and D code values of 3, 4,
5, and 6 would only be relevant for RINs generated under RFS2. As a
result, 2010 RINs generated under RFS1 would be subject to our proposed
RFS1/RFS2 transition provisions wherein they would be assigned to one
of the four annual standards that would apply in 2010 using their RR
and/or D codes. See Section III.G.3 for further description of how we
propose using RFS1 RINs to meet standards under RFS2.
Under RFS2, each batch-RIN generated would continue to uniquely
identify not only a specific batch of renewable fuel, but also every
gallon-RIN assigned to that batch. Thus the RIN would continue to be
defined as follows:
RIN: KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
Where:
K = Code distinguishing assigned RINs from separated RINs
YYYY = Calendar year of production or import
CCCC = Company ID
FFFFF = Facility ID
BBBBB = Batch number
RR = Code identifying the Equivalence Value
D = Code identifying the renewable fuel category
SSSSSSSS = Start of RIN block
EEEEEEEE = End of RIN block
B. New Eligibility Requirements for Renewable Fuels
Aside from the higher volume requirements, most of the substantive
changes that EISA makes to the RFS program affect the eligibility of
renewable fuels in meeting one of the four volume requirements.
Eligibility would be determined based on the types of feedstocks that
can be used, the land that can be used to grow feedstocks for renewable
fuel production, the processes that can be used to convert those
feedstocks into fuel, and the lifecycle greenhouse gas (GHG) emissions
that can be emitted in comparison to the gasoline or diesel that the
renewable fuel displaces. This section describes these eligibility
criteria and how we propose to include them in the RFS2 program.
1. Changes in Renewable Fuel Definitions
Under the existing Renewable Fuel Standard (RFS1), renewable fuel
is defined generally as ``any motor vehicle fuel that is used to
replace or reduce the quantity of fossil fuel present in a fuel mixture
used to fuel a motor vehicle''. The RFS1 definition includes motor
vehicle fuels produced from biomass material such as grain, starch,
fats, greases, oils, and biogas. The definition specifically includes
cellulosic biomass ethanol, waste derived ethanol, and biodiesel, all
of which are defined separately. (See 72 FR 23915.)
The definitions of renewable fuels under today's proposed rule
(RFS2) are based on the new statutory definition in EISA. Like the
existing rules, the definitions in RFS2 include a general definition of
renewable fuel, but unlike RFS1, we are including a separate definition
of ``Renewable Biomass'' which identifies the feedstocks from which
renewable fuels may be made.
Another difference in the definitions of renewable fuel is that
RFS2 contains three subcategories of renewable fuels: (1) Advanced
Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel. Each must
meet threshold levels of reduction of greenhouse gas emissions as
discussed in Section III.B.2. The specific definitions and how they
differ from RFS1 follow below.
a. Renewable Fuel and Renewable Biomass
``Renewable Fuel'' is defined as fuel produced from renewable
biomass and that is used to replace or reduce the quantity of fossil
fuel present in a transportation fuel. The definition of ``Renewable
Fuel'' now refers to ``transportation fuel'' rather than referring to
motor vehicle fuel. ``Transportation fuel'' is also defined, and means
fuel used in motor vehicles, motor vehicle engines, nonroad vehicles or
nonroad engines (except for ocean going vessels).
We propose to allow fuel producers and importers to include
electricity, natural gas, and propane (i.e., compressed natural gas
(CNG) and liquefied petroleum gas (LPG)) as a RIN-generating renewable
fuel in today's program only if they can identify the specific
quantities of their product which are actually used as a transportation
fuel, and if the fuel is produced from renewable biomass. This may be
possible for some portion of electricity, natural gas, and propane
since many of the affected vehicles and equipment are in centrally-
fueled fleets supplied under contract by a particular producer or
importer of natural gas or propane. A producer or importer of
electricity, natural gas, or propane who could document the use of his
product in a vehicle or engine would be allowed to generate RINs to
represent that product, if it met the definition of renewable fuel.
Given that the primary use of electricity, natural gas, and propane is
not for fueling vehicles and engines, and the producer generally does
not know how it will be used, we cannot require that producers or
importers of these fuels generate RINs for all the volumes they produce
as we do with other renewable fuels.
Our proposal to allow electricity, natural gas, and propane to
generate RINs under certain conditions is consistent with our treatment
of neat renewable fuels under RFS1 and EISA's requirement that all
transportation fuels be included in RFS2. With specific regard to
renewable electricity, Section 206 of EISA requires the EPA to conduct
a study of the feasibility of issuing credits under the RFS2 program
for renewable electricity used by electric vehicles. Once completed,
this study will provide additional information regarding the means by
which renewable electricity is able to generate RINs under the RFS2
program.
As an alternative to allowing producers and importers of
electricity, natural gas, and propane to generate RINs if they can
demonstrate that their product is a renewable fuel and it is used as
transportation fuel, we could allow or require parties who supply these
fuels to centrally fueled fleets to generate the RINs even if they are
not the producer of the fuel. This approach
[[Page 24922]]
would treat the supplier of the fuel to the fleet as the producer or
importer who then generates RINs, as they are the party who in effect
changes the fuel from a fuel that can be used in a variety of ways and
ensures that it is in fact used as transportation fuel. This
alternative approach might enable a larger volume of electricity,
natural gas, and propane that is made from renewable biomass and which
is actually used in vehicles or engines to be included in our proposed
fuels program as RIN-generating, since in many cases a supplier could
document the use of these fuels in vehicles or engines, while a
producer could not. In addition, in this case the supplier is the party
who causes the fuel to transition from general fuel supply to fuel
designated for use in motor vehicles or nonroad applications--in that
sense, the supplier is more like a producer or importer than the
upstream producer or importer. However, if we were to allow the
supplier of renewable electricity, natural gas, or propane to generate
RINs in such cases, it may also be appropriate to require suppliers of
fossil-based electricity, natural gas, or propane to determine a
Renewable Volume Obligation (RVO) that includes these fuels used as
transportation fuel. See Section III.F.3 for further discussion. We
request comment on this alternative approach for generating RINs for
renewable electricity, natural gas and propane.
The term ``Renewable Biomass'' as defined in EISA, means:
1. Planted crops and crop residue,
2. Planted trees and tree residues,
3. Animal waste material and byproducts,
4. Slash and pre-commercial thinnings (from non-federal
forestlands),
5. Biomass cleared from the vicinity of buildings and other areas
to reduce the risk of wildfire,
6. Algae, and
7. Separated yard waste or food waste.
Section III.B.4 of this preamble outlines our proposed
interpretations for most of the key terms contained in the EISA
definition of ``renewable biomass'' and possible approaches for
implementing the land restrictions on renewable biomass that are
included in EISA. It is worth noting here, however, that the statutory
definition of ``renewable biomass'' does not include a reference to
municipal solid waste (MSW) as did the definition of ``cellulosic
biomass ethanol'' in the Energy Policy Act of 2005 (EPAct), but instead
includes ``separated yard waste and food waste. EPA's proposed
definition of renewable biomass in today's regulation includes the
language present in EISA, and we propose to clarify in the regulations
that ``yard waste'' is leaves, sticks, pine needles, grass and hedge
clippings, and similar waste from residential, commercial, or
industrial areas. Nevertheless, EPA invites comment on whether the
definition of ``renewable biomass'' should be interpreted as including
or excluding MSW from the definition of renewable biomass.
While the lack of a reference to MSW and the new listing of
separated yard waste and food waste could be readily interpreted to
exclude MSW as a qualifying feedstock under RFS2, EPA believes there
are indications of ambiguity on this issue and solicits comment on
whether EPA can and should interpret EISA as including MSW that
contains yard and/or food waste within the definition of renewable
biomass. On the one hand, the reference in the statutory definition to
``separated yard waste and food waste,'' and the lack of reference to
other components of MSW (such as waste paper and wood waste) suggests
that only yard and food wastes physically separated from other waste
materials satisfy the definition of renewable biomass as opposed to the
yard and food waste present in MSW. This view would exclude unprocessed
MSW from any role in the development of renewable fuel under EISA, and
would also likely severely limit the amount of yard and food waste
available as feedstock for EISA-qualifying fuel, since large quantities
of these materials are disposed of as unprocessed MSW.
On the other hand, there are some indications that Congress may not
have specifically intended to exclude MSW from playing a role in the
development of renewable fuels under EISA. For example, ethanol
``derived from waste material'' and biogas ``including landfill gas''
are specifically identified as ``eligible for consideration'' in the
definition of advanced biofuel. While landfill gas is generated
primarily by the yard waste and food waste in a landfill, these wastes
typically are not separated from each other in a landfill. In addition,
Congress did not define the term ``separated'' and did not otherwise
specify the degree of ``separation'' required of yard and food waste in
the definition of renewable biomass. Thus, it might be reasonable to
consider these items sufficiently ``separated'' from other materials,
including non-waste materials, when food and yard waste is present in
MSW. In addition, the processing of MSW to fuel will effectively
separate out the materials in MSW that cannot be made into fuel, such
as glass and metal, and non-biomass portions of MSW (for example,
pastics) could be excluded from getting credit under the RFS program as
described in Section III.D.4. EPA invites comment on whether there is
enough separation of food and yard waste in MSW used in renewable fuel
production for MSW containing yard and food waste to meet the
definition of renewable biomass.
Approximately 35% by weight of MSW is paper wastes, and another 6%
by weight from wood wastes. Combined with food and yard wastes, more
than 60% by weight of MSW is biomass that could be used to make ethanol
and other renewable fuels.\5\ The volume of ethanol associated with MSW
as a feedstock is described in more detail in Section 1.1 of the Draft
Regulatory Impact Analysis (DRIA).
---------------------------------------------------------------------------
\5\ Construction and demolition (C&D) wastes are not typically
considered as elements of MSW. Because they are significant
feedstocks for the production of ethanol, we include such wastes in
our economic analysis (Section V). Therefore, for all practical
purposes, the discussion here as it pertains to whether MSW should
be included in the definition of ``renewable biomass'' also applies
to C&D wastes.
---------------------------------------------------------------------------
Our discussions with stakeholders indicate that a potential concern
with interpreting the definition of renewable biomass to include MSW
containing yard and/or food waste is that this approach may cause some
decrease in the amount of paper that is separated from the MSW waste
stream and recycled into paper products. We believe, however, that
current waste handling practices and current and anticipated market
conditions would continue to provide a strong incentive for paper
separation and recycling. A narrow reading of the statute to exclude
MSW-derived renewable fuel would directionally reduce the options
available for meeting the goal of EISA to reduce our dependence on
foreign sources of energy.
By including MSW containing yard and/or food waste in the
definition of renewable biomass, we could also allow renewable fuel to
be produced in part from certain plastics in the MSW waste stream. We
believe this could be appropriate given that plastics that would
otherwise be destined for landfills can be used for fuel and energy
production. We recognize that the definition of renewable biomass
generally includes only materials of a non fossil-fuel origin, and ask
that commenters consider this issue in their comments on whether: (1)
MSW containing yard and food waste should qualify as renewable biomass,
(2) if non-fossil portions of MSW should be included in the definition
of renewable biomass, and (3) if non-fossil portions of
[[Page 24923]]
MSW should not be included, whether the approach discussed in Section
III.D.4 can provide an appropriate means for excluding the non-fossil
portions.
Although we are proposing to exclude MSW from the definition of
``renewable biomass'' for the proposed rule, our analysis of renewable
fuel volume (discussed in Section V) assumes that MSW is included for
purposes of quantifying the potential future volume of renewable fuel.
EPA intends to resolve this matter in the final rule, and we solicit
comment on the approach that we should take.
b. Advanced Biofuel
``Advanced Biofuel'' is a renewable fuel other than ethanol derived
from corn starch and which must also achieve a lifecycle GHG emission
displacement of 50%, compared to the gasoline or diesel fuel it
displaces. As such, advanced biofuel would be assigned a D code of 3 as
shown in Table III.A-1.
``Advanced biofuel'' also may be biomass-based diesel, biogas
(including landfill gas and sewage waste treatment gas), butanol or
other alcohols produced through conversion of organic matter from
renewable biomass, and other fuels derived from cellulosic biomass, as
long as it meets the proposed 40-44% GHG emission reduction threshold.
``Advanced Biofuel'' is a renewable fuel other than ethanol derived
from corn starch and for which lifecycle GHG emissions are at least 40-
44% less than the gasoline or diesel fuel it displaces. Advanced
biofuel would be assigned a D code of 3 as shown in Table III.A-1.
While ``Advanced Biofuel'' specifically excludes ethanol derived
from corn starch, it includes other types of ethanol derived from
renewable biomass, including ethanol made from cellulose,
hemicellulose, lignin, sugar or any starch other than corn starch, as
long as it meets the proposed 40-44% GHG emission reduction threshold.
Thus, even if corn starch-derived ethanol were made so that it met the
proposed 40-44% GHG reduction threshold, it would still be excluded
from being defined as an advanced biofuel. Such ethanol, while not an
advanced biofuel, would still qualify as a renewable fuel for purposes
of meeting the standards.
``Advanced biofuel'' also may be biomass-based diesel, biogas
(including landfill gas and sewage waste treatment gas), butanol or
other alcohols produced through conversion of organic matter from
renewable biomass, and other fuels derived from cellulosic biomass, as
long as it is derived from renewable biomass and meets the proposed 40-
44% GHG emission reduction threshold.
c. Cellulosic Biofuel
Cellulosic biofuel is renewable fuel, not necessarily ethanol,
derived from any cellulose, hemicellulose, or lignin each of which must
originate from renewable biomass. It must also achieve a lifecycle GHG
emission reduction of at least 60%, compared to the gasoline or diesel
fuel it displaces. Cellulosic biofuel is assigned a D code of 1 as
shown in Table III.A-1. Cellulosic biofuel in general also qualifies as
both ``advanced biofuel'' and ``renewable fuel''.
The proposed definition of cellulosic biofuel for RFS2 is broader
in some respects than the RFS1 definition of ``cellulosic biomass
ethanol''. That definition included only ethanol, whereas the RFS2
definition of cellulosic biofuels includes any biomass-to-liquid fuel
in addition to ethanol. The definition of ``cellulosic biofuel'' in
RFS2 differs from RFS1 in another significant way. The RFS1 definition
provided that ethanol made at any facility--regardless of whether
cellulosic feedstock is used or not--may be defined as cellulosic if at
such facility ``animal wastes or other waste materials are digested or
otherwise used to displace 90% or more of the fossil fuel normally used
in the production of ethanol.'' This provision was not included in
EISA, and therefore does not appear in the definitions pertaining to
cellulosic biofuel in today's proposed rule.
d. Biomass-Based Diesel
Under today's proposed rule ``Biomass-based diesel'' includes both
biodiesel (mono-alkyl esters) and non-ester renewable diesel (including
cellulosic diesel). The definition is the same very broad definition of
``biodiesel'' that was in EPAct and in RFS1, with three exceptions.
First, EISA requires that such fuel be made from renewable biomass.
Second, its lifecycle GHG emissions must be at least 50% less than the
gasoline or diesel fuel it displaces. Third, the statutory definition
of ``Biomass-based diesel'' excludes renewable fuel derived from co-
processing biomass with a petroleum feedstock. In drafting the proposed
definition, we considered two options for how co-processing could be
treated. The first option would consider co-processing to occur only if
both petroleum and biomass feedstock are processed in the same unit
simultaneously. The second option would consider co-processing to occur
if renewable biomass and petroleum feedstock are processed in the same
unit at any time; i.e., either simultaneously or sequentially. Under
the second option, if petroleum feedstock was processed in the unit,
then no fuel produced from such unit, even from a biomass feedstock,
would be deemed to be biomass-based diesel.
We are proposing the first option to be used in the definition in
today's rule. Under this approach, a batch of fuel qualifying for the D
code of 2 that is produced in a processing unit in which only renewable
biomass is the feedstock for such batch, would meet the definition of
``Biomass-Based Diesel. Thus, serial batch processing in which 100%
vegetable oil is processed one day/week/month and 100% petroleum the
next day/week/month could occur without the activity being considered
``co-processing.'' The resulting products could be blended together,
but only the volume produced from vegetable oil would count as biomass-
based diesel. We believe this is the most straightforward approach and
an appropriate one, given that it would allow RINs to be generated for
volumes of fuel meeting the 50% GHG reduction threshold that is derived
from renewable biomass, while not providing any credit for fuel derived
from petroleum sources. In addition, this approach avoids the need for
potentially complex provisions addressing how fuel should be treated
when existing or even mothballed petroleum hydrotreating equipment is
retrofitted and placed into new service for renewable fuel production
or vice versa.
Under today's proposal, any fuel that does not satisfy the
definition of biomass-based diesel only because it is co-processed with
petroleum would still meet the definition of ``Advanced Biofuel''
provided it meets the 50% GHG threshold and other criteria for the D
code of 3. Similarly it would meet the definition of renewable fuel if
it meets a GHG emission reduction threshold of 20%. In neither case,
however, would it meet the definition of biomass-based diesel.
This restriction is only really an issue for renewable diesel and
biodiesel produced via the fatty acid methyl ester (FAME) process. For
other forms of biodiesel, it is never made through any sort of co-
processing with petroleum.\6\
[[Page 24924]]
Producers of renewable diesel must therefore specify whether or not
they use ``co-processing'' to produce the fuel in order to determine
the correct D code for the RIN.
---------------------------------------------------------------------------
\6\ The production of biodiesel (mono alkyl esters) does require
the addition of methanol which is usually derived from natural gas,
but which contributes a very small amount to the resulting product.
We do not believe that this was intended by the statute's reference
to ``co-processing'' which we believe was intended to address only
renewable fats or oils co-processed with petroleum in a hydrotreater
to produce renewable diesel.
---------------------------------------------------------------------------
e. Additional Renewable Fuel
The statutory definition of ``additional renewable fuel'' specifies
fuel produced from renewable biomass that is used to replace or reduce
fossil fuels used in home heating oil or jet fuel. EISA indicates that
EPA may allow for the generation of credits for such additional
renewable fuel that will be valid for compliance purposes. Under the
RFS program, RINs operate in the role of credits, and RINs are
generated when renewable fuel is produced rather than when it is
blended. In most cases, however, renewable fuel producers do not know
at the time of fuel production (and RIN generation) how their fuel will
ultimately be used.
Under RFS1, only RINs assigned to renewable fuel that was blended
into motor vehicle fuel are valid for compliance purposes. As a result,
we created special provisions requiring that RINs be retired if they
were assigned to renewable fuel that was ultimately blended into
nonroad fuel. The new EISA provisions regarding additional renewable
fuel make the RFS1 requirement for retiring RINs unnecessary if
renewable fuel is blended into heating oil or jet fuel. As a result, we
propose modifying the regulatory requirements to allow RINs assigned to
renewable fuel blended into heating oil or jet fuel to continue to be
valid for compliance purposes.
2. Lifecycle GHG Thresholds
As part of the new definitions that EISA creates for cellulosic
biofuel, biomass-based diesel, advanced biofuel, and renewable fuel,
EISA also sets minimum performance measures or ``thresholds'' for
lifecycle GHG emissions. These thresholds represent the percent
reduction in lifecycle GHGs that is estimated to occur when a renewable
fuel displaces gasoline or diesel fuel. Table III.B.2-1 lists the
thresholds required by EISA.
Table III.B.2-1--Required Lifecycle GHG Thresholds
[Percent reduction from a 2005 gasoline or diesel baseline]
------------------------------------------------------------------------
------------------------------------------------------------------------
Renewable fuel................................................. 20
Advanced biofuel............................................... 50
Biomass-based diesel........................................... 50
Cellulosic biofuel............................................. 60
------------------------------------------------------------------------
There are also special provisions for each of these thresholds:
Renewable fuel: The 20% threshold only applies to renewable fuel
from new facilities that commenced construction after December 19,
2007, with an additional exemption from the 20% threshold for ethanol
plants that commenced construction in 2008 or 2009 and are fired with
natural gas, biomass, or any combination thereof. Facilities not
subject to the 20% threshold would be ``grandfathered.'' See Section
III.B.3 below for a complete discussion of grandfathering. Also, EPA
can adjust the 20% threshold to as low as 10%, but the adjustment must
be the minimum possible, and the resulting threshold must be
established at the maximum achievable level based on natural gas fired
corn-based ethanol plants.
Advanced biofuel and biomass-based diesel: The 50% threshold can be
adjusted to as low as 40%, but the adjustment must be the minimum
possible and result in the maximum achievable threshold taking cost
into consideration. Also, such adjustments could be made only if it was
determined that the 50% threshold was not commercially feasible for
fuels made using a variety of feedstocks, technologies, and processes.
As described more fully in Section VI.D, we are proposing that the GHG
threshold for advanced biofuels be adjusted to 44% or potentially as
low as 40% depending on the results from the analyses that will be
conducted for the final rule.
Cellulosic biofuel: Similarly to advanced biofuel and biomass-based
diesel, the 60% threshold applicable to cellulosic biofuel can be
adjusted to as low as 50%, but the adjustment must be the minimum
possible and result in the maximum achievable threshold taking cost
into consideration. Also, such adjustments could be made only if it was
determined that the 60% threshold was not commercially feasible for
fuels made using a variety of feedstocks, technologies, and processes.
Our analyses of lifecycle GHG emissions, discussed in detail in
Section VI, included all GHGs related to the full fuel cycle, including
all stages of fuel and feedstock production and distribution, from
feedstock generation and extraction through distribution, delivery, and
use of the finished fuel. They included direct emissions and any
significant indirect emissions such as significant emissions from land
use changes. These lifecycle analyses were used to determine whether
the thresholds shown in Table III.B.2-1 should be adjusted downwards
and which specific combinations of feedstock, fuel type, and production
process met those thresholds under the assumption of a 100-year
timeframe and 2% discount rate for GHG emission impacts.
We are not proposing to adjust any of these thresholds. However, we
may adjust the GHG threshold for biomass-based diesel and/or advanced
biofuel downward for the final rule based on additional lifecycle GHG
analyses and further assessments of the market potential for volumes
that can meet the requirements for these categories of renewable fuel.
As explained in more detail in Section VI.D, ethanol produced from
sugarcane sugar has been estimated to have a lifecycle GHG performance
of 44% (under the assumption of a 100 year timeframe and 2% discount
rate), short of the 50% threshold specified in EISA. Ethanol from
sugarcane is one of the few currently commercial pathways that have the
potential to meet the requirements for advanced biofuel in the near
term (in addition to cellulosic biofuel and biomass-based diesel which
are a subset of advanced biofuel, and any other new fuels that may
arise), and the only such pathway that was subjected to lifecycle
analysis to date. If ethanol from sugarcane does not qualify as
advanced biofuel, it is likely that it would not be commercially
feasible for the advanced biofuel volume requirements to be met in the
near term. We request comment on whether it would be necessary to
adjust the GHG threshold for advanced biofuel. For similar reasons, as
discussed in more detail in Section VI.D, we are also seeking comment
on the need to adjust the GHG threshold for biomass-based diesel.
3. Renewable Fuel Exempt From 20 Percent GHG Threshold
EISA amends section 211(o) of the Clean Air Act to provide that
renewable fuel produced from new facilities which commenced
construction after December 19, 2007 must achieve at least a 20%
reduction in lifecycle greenhouse gas emissions compared to baseline
lifecycle greenhouse gas emissions.\7\ Facilities that commenced
construction before December 19, 2007 are ``grandfathered'' and thereby
exempt from the 20% GHG reduction requirement.
---------------------------------------------------------------------------
\7\ Section 211(o)(2)(A)(i) of the Clean Air Act as amended by
EISA. Note that this is not a prohibition--facilities that make
ethanol can continue to do so. It is a minimum requirement for
facilities to generate RINs under today's proposed rule; failure to
meet such requirements means that the ethanol produced from such
facilities cannot generate RINs.
---------------------------------------------------------------------------
[[Page 24925]]
For facilities that produce ethanol and for which construction
commenced after December 19, 2007, section 210 of EISA states that
``for calendar years 2008 and 2009, any ethanol plant that is fired
with natural gas, biomass, or any combination thereof is deemed to be
in compliance with the 20% threshold.'' We refer to these facilities as
``deemed compliant.'' This provision does not specify whether such
facilities are deemed to be in compliance only for the period of 2008
and 2009, or indefinitely. Nor does EISA specify a date by which such
qualifying facilities must have started operation. Although the Act is
unclear as to whether their special treatment is only for 2008/2009, or
for a longer time period, we believe that it would be a harsh result
for investors in these new facilities, and generally inconsistent with
the energy independence goals of EISA, for these new facilities to only
be guaranteed two years of participation in the RFS2 program. We
propose that the statute be interpreted to mean that fuel from such
qualifying facilities, regardless of date of startup of operations,
would be exempt from the 20% GHG threshold requirement for the same
time period as facilities that commence construction prior to December
19, 2007, provided that such plants commence construction prior to
December 31, 2009, complete such construction in a reasonable amount of
time, and continue to burn only natural gas, biomass, or a combination
thereof. Therefore, we believe that they should be treated like
grandfathered facilities. We seek comment, however, on the alternative
in which after 2009, such plants must meet the 20% threshold in order
to generate RINs for renewable fuel produced.
Based on our survey of ethanol plants in operation, as well as
those not yet in operation but which commenced construction prior to
December 19, 2007, it is likely that production capacity of ethanol
from all such facilities will reach 15 billion gallons. (See Section
1.5.1.4 of the DRIA.) This volume of ethanol will be excluded from
having to meet the 20% GHG threshold by the grandfathering and deemed
compliant provisions of EISA.\8\ For ease of reference, we will refer
to both these provisions as the ``exemption provisions'' of EISA.
---------------------------------------------------------------------------
\8\ The grandfathering and deemed compliant provisions in EISA
sections 202 and 210 do not apply to the advanced biofuels, biomass-
based diesel or cellulosic biofuel standards for which the Act
requires a 50 or 60% GHG reduction threshold to be met regardless of
when the facilities producing such fuels are constructed.
---------------------------------------------------------------------------
EISA does not define the term ``new facility'' and, as mentioned
above, does not clarify whether ``deemed compliant'' facilities have
that status for only 2008 and 2009, or for a longer time period. EPA
seeks, in interpreting these terms, to avoid long-term backsliding with
respect to environmental performance and to also provide a level
playing field for future investments. Thus, we want to avoid incentives
that would allow overall GHG performance to worsen via expansion at
older plants with poorer GHG performance or by modifications such as
switches to more polluting process heat sources, such as coal. At the
same time, we also want to offer protection for historical business
investments that were made prior to enactment of EISA, and we want
future significant investments to meet the GHG reduction standards of
the Act. Finally we want to avoid excessive case-by-case decision
making where possible, and seek instead a rule that offers ease of
implementation while providing certainty to EPA and the regulated
industry.
We are proposing one basic approach to the exemption provisions and
seeking comment on five additional options. In fashioning the basic
proposal and alternative options for exempted facilities, we considered
aspects of exemption approaches elsewhere in the CAA and EPA
regulations to evaluate whether they would foster the above-described
objectives. We are only looking to these other provisions for guidance
and are not bound to follow any already-established approach for a
different statutory provision (especially as those other provisions may
contain definitions that Congress did not incorporate here).
a. Definition of Commence Construction
In defining ``commence'' and ``construction'', we wanted a clear
designation that would be broad enough to avoid facility-specific
issues, but narrow enough to prevent new facilities (i.e., post-
December 19, 2007) from being grandfathered. We believe that the
definitions of ``commence'' and ``Begin actual construction'' in the
Prevention of Significant Deterioration (PSD) regulations, which draws
upon definitions in the Clean Air Act, served this purpose. (40 CFR
52.21(b)(9) and (11)). Specifically, under the PSD regulations,
``commence'' means that the owner or operator has all necessary
preconstruction approvals or permits and either has begun a continuous
program of actual on-site construction to be completed in a reasonable
time, or entered into binding agreements which cannot be cancelled or
modified without substantial loss.'' Such activities include, but are
not limited to, ``installation of building supports and foundations,
laying underground pipe work and construction of permanent storage
structures.'' We have added language to the definition that is
currently not in the PSD definition with respect to multi-phased
projects. We are proposing that for multi-phased projects, commencement
of construction of one phase does not constitute commencement of
construction of any later phase, unless each phase is ``mutually
dependent'' on the other on a physical and chemical basis, rather than
economic.
The PSD regulations provide additional conditions beyond what
constitutes commencement. Specifically, the regulations require that
the owner or operator ``did not discontinue construction for a period
of 18 months or more and completed construction within a reasonable
time.'' (40 CFR 52.21(i)(4)(ii)(c). While ``reasonable time'' may vary
depending on the type of project, we believe that with respect to
renewable fuel facilities, a reasonable time to complete construction
is no greater than 3 years from initial commencement of construction.
We seek comment on the use of these definitions.
b. Definition and Boundaries of a Facility
We propose that the grandfathering and deemed compliant exemptions
apply to ``facilities.'' Our proposed definition of this term is
similar in some respects to the definition of ``building, structure,
facility, or installation'' contained in the PSD regulations in 40 CFR
52.21. We have modified the definition, however, to focus on the
typical renewable fuel plant. We therefore propose to describe the
exempt ``facilities'' as including all of the activities and equipment
associated with the manufacture of renewable fuel which are located on
one property and under the control of the same person or persons.
c. Options Proposed in Today's Rulemaking
We are proposing one basic approach to the grandfathering
provisions and seeking comment on five additional options. The basic
approach would provide an indefinite extension of grandfathering and
deemed compliant status but with a limitation of the exemption from the
20% GHG threshold to a baseline volume of renewable fuel. The five
additional options for which we seek comment are: (1) Expiration of
exemption for grandfathered and ``deemed compliant'' status when
facilities undergo sufficient changes to
[[Page 24926]]
be considered ``reconstructed''; (2) Expiration of exemption 15 years
after EISA enactment, industry-wide; (3) Expiration of exemption 15
years after EISA enactment with limitation of exemption to baseline
volume; (4) ``Significant'' production components are treated as
facilities and grandfathered or deemed compliant status ends when they
are replaced; and (5) Indefinite exemption and no limitations placed on
baseline volumes.
i. Basic Approach: Grandfathering Limited to Baseline Volumes
We are proposing and seeking comments on an option which generally
limits the volume of any renewable fuel for which a grandfathered and
deemed compliant facility can generate RINs without complying with the
20% GHG reduction threshold to the capacity volume specified in a state
or Federal air permit or the greater of nameplate capacity or actual
production. This approach is similar to how we have treated small
refiner flexibilities under our other fuel rules. As a sub-option to
this approach, we also seek comment on a provision whereby facilities
would lose their status if they switch to a process fuel or feedstock
which results in an increase of GHG emissions.
(1) Increases in Volume of Renewable Fuel Produced at Grandfathered
Facilities due to Expansion
For facilities that commenced construction prior to December 19,
2007, we are proposing to define the baseline volume of renewable fuel
exempt from the 20% GHG threshold requirement to be the maximum
volumetric capacity of the facility as allowed in any applicable state
air permit or Federal Title V operating permit. If the capacity of a
facility is not stipulated in such air permits, then the grandfathered
volume is the greater of the nameplate capacity of the facility or
historical annual peak production prior to enactment of EISA. Volumes
greater than this amount which may typically be due to expansions of
the facility which occur after December 19, 2007, would be subject to
the 20% GHG reduction requirement in order for the facility to generate
RINs for the incremental expanded volume. The increased volume would be
considered as if produced from a ``new facility'' which commenced
construction after December 19, 2007. Changes that might occur to the
mix of renewable fuels produced within the facility would remain
grandfathered as long as the overall volume fell within the baseline
volume.
The baseline volume would be defined as above for deemed compliant
facilities with the exception that if the maximum capacity is not
stipulated in air permits, then the exempt volume would be the maximum
annual peak production during the plant's first three years of
operation. In addition, any production volume increase that is
attributable to construction which commenced prior to December 31, 2009
would be exempt from the 20% GHG threshold, provided that the facility
continued to use natural gas, biomass or a combination thereof for
process energy. Because deemed compliant facilities owe their status to
the fact that they use natural gas, biomass or a combination thereof
for process heat, we propose that their status would be lost, and they
would be subject to the 20% GHG threshold requirement, at any time that
they change to a process energy source other than natural gas and/or
biomass. Finally, because EISA limits deemed compliant facilities to
ethanol facilities, we propose that if there are any changes in the mix
of renewable fuels produced by the facility that only the ethanol
volume remain grandfathered. We solicit comment, however, on whether
the statute could be read to allow deemed compliant facilities to be
treated the same as grandfathered facilities by allowing a mix of
renewable fuels.
Volume limitations contained in air permits may be defined in terms
of peak hourly production rates or a maximum annual capacity. If they
are defined only as maximum hourly production rates, they would need to
be converted to an annual rate. We believe that assuming 24-hour per
day production over 365 days per year (8,760 production hours) may
overstate nameplate capacity. In other regulations that pertain to
refinery operations, we have assumed a conversion rate of 90% of the
total hours in a year (7884 production hours). We seek comment on what
would be an appropriate conversion rate for renewable fuel facilities.
The facility registration process (see Section III.C) would be used
to define the baseline volume for individual facilities. Owners and
operators would submit information substantiating the nameplate
capacity of the plant, as well as historical annual peak capacity if
such is greater than nameplate capacity. Subsequent expansions at a
grandfathered that result in an increase in volume would subject the
increase in volume to the 20% GHG emission reduction threshold (but not
the original baseline volume). Thus, any new expansions would need to
be designed to achieve the 20% GHG reduction threshold if the facility
wants to generate RINs for that volume. Such determinations would be
made on the basis of EPA-defined corn ethanol fuel pathway categories
that are deemed to represent such 20% reduction. As an alternative
approach to the greater of nameplate capacity or historical annual peak
capacity, we seek comment on an approach in which the baseline volume
is the actual volume of renewable fuel produced during the 2006
calendar year, where adequate data is available. Since there has been a
particularly high demand for ethanol in recent years, the use of 2006
data may be a fair representation of the real production capacity for
most plants. For plants that have not operated for an adequate shake
down period, the information in the state or Federal air permit could
be used and if this is not available, the nameplate capacity could be
used. As mentioned above, deemed compliant facilities would be exempt
from the 20% GHG threshold for baseline volumes and any additional
volumes regarding which construction commenced prior to December 31,
2009.
We recognize, however, that some debottlenecking type changes may
cause increases in volume that are within a plant's inherent capacity.
To account for this in past regulations (e.g., 40 CFR 80.552 and 554)
we allowed for an increase of 5% above the baseline volume. Based on
conversations with builders of ethanol plants, however, such plants
have often been debottlenecked to exceed nameplate capacity by 20% and
sometimes much higher. We seek comment on whether we should allow a 10%
tolerance on the baseline volume for which RINs can be generated
without complying with the 20% GHG reduction threshold. Once that 10%
increase in volume is exceeded, the total increase above baseline
volume would then be subject to the 20% GHG reduction requirement in
order to generate RINs. We also seek comment on tolerance values in the
5 to 20% range.
Our guiding philosophy of protecting historical business
investments that were made to comply with the provisions of RFS1 is
realized by allowing production increases within a plant's inherent
capacity. At the same time, the alternative of requiring compliance
with the 20% GHG reduction requirement for increases in volume above
10% over the baseline volume, would place new volumes from
grandfathered facilities on a level playing field with product from new
grass roots facilities. We believe that a level playing field for new
investments
[[Page 24927]]
is fair and consistent with the provisions of EISA.
(2) Replacements of Equipment
If production equipment such as boilers, conveyors, hoppers,
storage tanks and other equipment are replaced, it would not be
considered construction of a ``new facility'' under this option of
today's proposal--the baseline volume of fuel would continue to be
exempt from the 20% GHG threshold. We discuss in a sub-option in
III.B.3.c.i(4) below in which if the replacement unit uses a higher
polluting fuel in terms of GHG emissions such replacement would render
the facility a new facility, and it would no longer be exempt from the
20% GHG threshold. We also solicit comment on an approach that would
require that if coal-fired units are replaced, that the replacement
units must be fired with natural gas or biofuel for the product to be
eligible for RINs that do not satisfy the 20% GHG threshold.
(3) Registration, Recordkeeping and Reporting
Facility owner/operators would be required to provide evidence and
certification of commencement of construction. Owner/operators must
provide annual records of process fuels used on a BTU basis, feedstocks
used and product volumes. For facilities that are located outside the
United States (including outside the Commonwealth of Puerto Rico, the
U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the
Northern Mariana Islands) owners would be required to provide
certification as well. Since the definition of commencement of
construction includes having all necessary air permits, we would
require that facilities outside the United States to certify that such
facilities have obtained all necessary permits for construction and
operation required by the appropriate national and local environmental
agencies.
(4) Sub-Option of Treatment of Future Modifications
We seek comment on a sub-option to the basic approach whereby
facilities would lose their grandfathered status if they switch to a
process fuel or feedstock which results in an increase of GHG
emissions. Some facilities may keep production volumes the same, but
change some or all of their feedstocks and energy sources, thus causing
a facility's product to fall further below the GHG performance for the
fuel pathway it produced at the time of enactment. We are therefore
seeking comment on an approach to limit the initial grandfathering only
for the fuel pathways that applied during 2007, when establishing the
volume baseline. Table III.B.3.c.i-1 below presents a ranking of fuels
and feedstock by fuel pathway in order of life cycle GHG emissions (as
discussed further in Section VI.E). (Table III.B.3.c.i-1 is based on
the table of fuel pathways contained in proposed regulations 40 CFR
80.1426.) Since the majority of facilities under consideration in this
portion of the rulemaking consists of ethanol plants, the table below
is limited to those types. Any changes to a facility that shift it to a
feedstock or use of a process energy source that results in higher GHG
emissions on the basis of the ranking categories in Table III.B.3.c.i-1
below would terminate the facility's grandfathered status.
For example, an ethanol dry mill plant using natural gas for
process heat, as well as combined heat and power (CHP), is ranked as
``2'' in the table below. If the plant (or any portion of the plant)
switches to coal, it is ranked as ``4''. The higher number indicates an
increase in GHG emissions. Therefore in this example, the plant is
considered to have undertaken a modification that increases GHG
emissions, would render the facility as ``new'' and its grandfathered
status would end. Similarly, replacements of equipment that worsen GHG
emissions would also terminate grandfathered status. (For replacements
of equipment that do not change the fuel, nor result in an increase in
volume of renewable fuel, the grandfathered status of the plant would
remain, as discussed in Section III.B.3.c.i(2) above.)
Table III.B.3.c.i-1--Groups of Renewable Fuel Facilities by Fuel
Feedstock and Process Energy
------------------------------------------------------------------------
Production process
Feedstock requirements Ranking
------------------------------------------------------------------------
Starch from corn, wheat, barley, --Process heat derived 1
oats, rice, or sorghum. from biomass.
Starch from corn, wheat, barley, --Dry mill plant........ 2
oats, rice, or sorghum.
--All process heat
derived from natural
gas.
--Combined heat and
power (CHP).
--Fractionation of
feedstocks.
--Dried distillers
grains.
Starch from corn, wheat, barley, --Dry mill plant........ 3
oats, rice, or sorghum.
--All process heat
derived from natural
gas.
--Wet distillers grains.
Starch from corn, wheat, barley, --Dry mill plant........ 4
oats, rice, or sorghum.
--All or part of process
heat derived from coal.
--Combined heat and
power (CHP).
--Fractionation of
feedstocks.
--Membrane separation of
ethanol.
--Raw starch hydrolysis.
--Dried distillers
grains.
Starch from corn, wheat, barley, --Dry mill plant........ 5
oats, rice, or sorghum.
--All or part of process
heat derived from coal.
--Combined heat and
power (CHP).
--Fractionation of
feedstocks.
--Membrane separation of
ethanol.
--Wet distillers grains.
Sugarcane sugar.................. --Process heat derived 1
from sugarcane bagasse.
Sugarcane sugar.................. --Process heat derived 2
from natural gas.
Sugarcane sugar.................. --Process heat derived 3
from coal.
------------------------------------------------------------------------
[[Page 24928]]
We considered whether improvements at a facility (i.e., a fuel
switch from coal to natural gas) that still result in GHG performance
less than 20% should be credited to allow the facility to increase its
baseline volume. We decided not to propose such an approach because it
would take away an incentive for new plants that achieve greater than
20% GHG reduction to be constructed. As such, this would go against our
guiding principle of providing equal opportunities for future
investments in new plants.
We recognize that there may be combinations of changes made at a
plant, some of which may worsen GHG emissions and others which may
cause an improvement and that not all such combinations can be taken
into account in a single table of fuel pathways. We seek comment on
ways to address such combinations.
ii. Alternative Options for Which We Seek Comment
(1) Facilities That Meet the Definition of ``Reconstruction'' Are
Considered New
An alternative approach on which we are seeking comment would
consider whether a facility is effectively a ``new'' facility with
respect to the costs incurred in maintaining the plant over time.
Starting in 2010, we would require facility owners to report annually
(specifically by January 31) to EPA the expenses for replacements,
additions, and repairs undertaken at facilities since start up of the
facility through the year prior to reporting. The Agency would then
determine whether the degree of such activities warrants considering
the facility as effectively ``new''. That substantial rebuilding or
modernization may render an existing facility a new facility for
regulatory purposes finds analogies in other Clean Air Act regulatory
programs. For example, under the New Source Performance Standards
(NSPS) equipment that has been ``reconstructed'' as defined in 40 CFR
60.15 is considered new. Specifically, ``reconstruction'' is defined in
40 CFR 60.15 as ``the replacement of components of an existing facility
to such an extent that the fixed capital cost of the new components
exceeds 50% of the fixed capital cost that would be required to
construct a comparable entirely new facility. In addition to the NSPS
program, regulations such as the recently promulgated standards for
locomotive and marine engines (73 FR 25160; May 6, 2008) use a more
encompassing concept of reconstruction and consider a vessel to be new
if it is modified such that the value of the modifications exceeds 50%
of the value of the modified vessel. We are seeking comment on an
approach wherein upon the Agency's determination that costs of
replacements, repairs and upgrades conducted since the start-up of the
facility meet the test of ``reconstruction'' (i.e., the costs equal or
exceed 50% of what it would cost to rebuild), that the facility would
be considered effectively new, and would be subject to the 20% GHG
reduction requirements.
The application of the definition of reconstruction in the NSPS
program occurs on an equipment-wide rather than on a plant-wide basis.
Under this option, we would apply the concept of a ``new'' facility on
a plant-wide basis similar to the approach we have taken in the
recently promulgated locomotive and marine standards. We believe that a
plant-wide approach is appropriate under RFS2 because it is not the
emissions from individual pieces of equipment that are being regulated.
Rather, the 20% GHG reduction standard applies to the renewable fuel
produced by the facility, and it is logical to consider all of the
equipment and structures at the facility involved in producing the
product in evaluating when a grandfathered facility has been
reconstructed. For these reasons, we believe that it would be
reasonable to apply the definition of ``new'' on a plant-wide basis.
Also, since upgrades, replacements and repairs will occur on an ongoing
basis we would consider rebuilding or reconstruction to occur over time
as the accumulation of all individual upgrades, replacements and
repairs.
The NSPS definition also requires that it be ``technologically and
economically feasible for the reconstructed facility to meet applicable
standards that apply to new facilities.'' We do not think that EISA
requires this additional consideration, and also do not believe that
there is any compelling public policy justification for allowing a
reconstructed facility to continue to make renewable fuel that does not
meet the 20% GHG reduction standard based upon a claim that it is
technologically or economically infeasible. EPA's experience in the New
Source Review (NSR) program has demonstrated that it is extremely
difficult to clearly define what the terms ``technologically and
economically feasible'' mean. Aside from such definitional
difficulties, however, and as discussed in Section III.B.3.c.ii(2)
below, we believe that it is technologically feasible to meet the 20%
GHG reduction and with proper planning would be economically so, as
well. Therefore, this alternative option would not require such a
showing.
Our assessment of whether a facility has been reconstructed would
be based on application of an appropriate cost model such as U.S.
Department of Agriculture's cost estimation model for construction of
new ethanol plants described by Kwiatkowski, J. et al. (2006) \9\.
Costs associated with the costs of repair and replacement of all parts
(including the labor associated with replacement and repair), would be
included in such calculation, regardless of the parts' intended useful
life. We seek comment on whether to also include costs associated with
employee labor related to routine maintenance, and also whether the
costs of repairs and replacements at the facility should be limited
only to the property directly related to the production of
biofuels.\10\
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\9\ Kwiatkowski, J.R., McAloon, A., Taylor, F. Johnson, D. 2006.
``Modeling the process and costs of fuel ethanol production by the
corn dry-grind process.'' Industrial Crops and Products 23 (2006)
288-296.
\10\ We note that under NSPS the costs considered in determining
whether the definition of reconstruction has been met are restricted
to the capital costs of equipment and materials. The RFS2 program is
authorized from EISA which does not rely on the definitions of
``modification'' and ``routine maintenance and repair'' that are in
NSPS and other new source programs (e.g., New Source Review,
National Emission Standards for Hazardous Pollutants). Since our
application of the term ``reconstruction'' assumes that over time,
renewable fuel facilities may become substantially rebuilt it is
therefore appropriate to consider not only equipment replacements
but some of the labor costs associated with such replacements.
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Under this alternative option, the volume of renewable fuel that
qualifies for an exemption from the 20% GHG threshold would remain
fixed at the baseline volume as in the basic option described in
III.B.3(c)(i). However, we also seek comment on whether the volume of
renewable fuel at a grandfathered facility should be allowed to
increase above baseline volumes under this option. Specifically,
increases in volume could be exempt until such time as the entire plant
is deemed to have been reconstructed. In making such assessment and
applying the 50% test, the basis for the cost of a ``comparable
entirely new facility'' would be a facility with the original baseline
volume. For example, if an existing plant has a 100 million gallon per
year capacity and expands its volume to 120 million gallons per year,
reconstruction would occur if the costs incurred over time equal or
exceed 50% of the cost of a comparable 100 million gallon per year
facility.
Under this alternative option, owner/operators or other responsible
parties would be required to provide records of costs incurred for
additions, replacements, and repairs that have
[[Page 24929]]
occurred since start-up. Such records would be provided on an annual
basis to EPA by May 31, and would include cumulative cost information
up to the prior year.
We recognize that implementation of a facility-wide definition of
``reconstruction'' would be complex. Records of costs since start-up
may not be available for older facilities. Also, this alternative
option requires EPA enforcement staff to have sufficient financial
knowledge and experience to be able to evaluate the veracity of claims
regarding various types of expenditures. Calculating the costs of
repairs and replacements also poses challenges. Specifically, as
discussed above, we seek comment on whether the costs of routine
maintenance and repair should be included in such assessments. Were
such costs to be included, the determination of whether a replacement
or a repair is routine may not always be straightforward. In addition
to the recordkeeping and implementation issues, however, there is an
important policy consideration that is also significant. As in the case
of the NSR program, where many industry representatives have argued
that the program has a chilling effect on projects that could provide
environmental benefits, the reconstruction approach in this alternative
option could also provide a disincentive to implementation of safety
and environmental projects. Thus, this option could have the unintended
consequence of causing facilities to refrain from investing in projects
that will increase safety and efficiency and reduce emissions in order
to avoid triggering the 50% cost threshold. We seek comment on this
issue.
(2) Expiration Date of 15 Years for Exempted Facilities
The above discussion highlights potential complexities in
implementing the option of considering reconstruction of exempted
facilities on a case-by-case basis. These include potential disputes
over how to calculate costs, as well as verifying records of
expenditures. In addition, that option has as a potential unintended
consequence, a disincentive for investment in projects that could
improve safety, efficiency and environmental performance. As an
alternative to the case-by case approach described above, this option
offers a practical way of implementing the reconstruction concept by
establishing an expiration date for all grandfathered and deemed
compliant facilities after a period of 15 years from enactment of EISA
(i.e., after December 31, 2022), regardless of when such facilities
commenced construction or began operation. Under such option, the
grandfathered and deemed compliant facilities would be subject to the
20% GHG threshold starting on January 1, 2023. Renewable fuel produced
from these facilities after this date would be required to comply with
the 20% threshold requirement in order to generate RINs.
Based on our discussions with companies that construct ethanol
plants, we believe that facility owners will make decisions about
equipment replacements and technology upgrades that will continue to
improve the overall operating costs and energy efficiency of the plant
which ultimately lead to improvements in GHG emission performance as
well. In particular, energy-intensive processes in the plant are likely
to be replaced or upgraded to increase fuel and operating efficiency,
thus reducing operating costs of the plant, and increasing output.
Nilles (2006) reports that the first line of next-generation dry-grind
ethanol plants was built with mild steel components and that in 10 or
15 years, those components will need to be replaced entirely--most
likely with stainless steel. Of particular importance is that durable
materials as well as weaker materials all require maintenance and
replacement. As such, the components and equipment in ethanol
facilities are designed to be easily replaced and to allow simple
maintenance.\11\
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\11\ Nilles, D. 2006. ``Time Testing''; Ethanol Producer
Magazine, May, Vol. 12, No. 5.
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Using cost data contained in the U.S. Department of Agriculture's
cost estimation model for construction of new ethanol plants described
by Kwiatkowski, J. et al (2006), we calculated the cost of a
replacement of specific components in a hypothetical 100 million gallon
ethanol facility.12 13 We assumed that all steel tanks are
replaced with stainless steel tanks, and that specific combustion
equipment is replaced. Combining replacement costs with maintenance,
repairs, upgrades and supply costs (at 2% of the capital cost of the
facility per year), we calculated that over 15 years, the accumulated
costs range from 50% to 75% of the capital cost of an equivalent
facility.\14\
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\12\ Op Cit., Kwiatkowski, et al. (2006).
\13\ Note to Docket (EPA-HQ-OAR-2005-0161), ``Analysis of Costs
of Replacements and Repairs at a Hypothetical 100 MM GPY Ethanol
Facility''; from Barry Garelick, Environmental Protection
Specialist, Assessment and Standards Division, Office of
Transportation and Air Quality; October 16, 2008.
\14\ The USDA model gives the installed capitol cost of a 40
million GPY facility at approximately $60 million (2006 dollars).
The model also gives replacement costs of individual components
(steel tanks and the ring dryer) at about $13 million. Ongoing
maintenance costs are estimated at about $6 million per year.
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As discussed in Section 1.5.1.3 of the DRIA, per our conversations
with builders of ethanol plants, the changes and upgrades would be made
to improve competitiveness which will also improve operating and fuel
efficiency, thus tending to improve overall GHG performance of the
plant. The high price of natural gas has many ethanol plants
considering alternative fuel sources. Greater biofuel availability and
potential low life cycle green house gas emissions incentives may
further encourage ethanol producers to switch from fossil fuels for
process heat to biomass based fuels. In addition, ethanol producers may
consider energy saving changes to the ethanol production process.
Several process changes, including raw starch hydrolysis, corn
fractionation, corn oil extraction, and membrane separation, are likely
to be adopted to varying degrees. Since such changes would be
consistent with ultimately achieving the 20% GHG reduction required of
new facilities, we believe it is reasonable to expect that the newly
rebuilt facilities could meet the 20% GHG reduction threshold, based on
the results of a life cycle analysis.\15\
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\15\ Unless and until EPA conducts facility specific life cycle
analyses, however, compliance with the 20% GHG reduction threshold
would be made on the basis of fuel pathways as described in Section
III.D.2.
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We solicit further information and data, particularly evidence of
the types of replacements and ongoing maintenance that has occurred at
existing plants and what is projected to occur in the future. We will
evaluate such information along with other comments received during the
public comment period. We also solicit comment on whether a period
other than 15 years may be more appropriate.
Under this approach, facilities that are exempted could expand
their volume of renewable fuel production, or could switch fuels or
feedstocks within the 15 year exemption period without fear of losing
their temporary exemption. While some of these activities have the
potential to worsen GHG emissions further below the 20% threshold
requirement, we believe that the imposition of an expiration date will
result in modifications to facilities that tend to increase the
efficiency and GHG performance of the plant rather than worsen them.
The need for compliance with the 20% threshold requirement by a date
certain would provide an incentive for owners and operators of
[[Page 24930]]
such plants to ensure the changes they make over time would bring them
into compliance with the 20% requirement at the end of the 15 year
period.
While the facilities built in 2008 and 2009 would be in operation
for less than 15 years, the majority of ethanol plants will have been
in operation for 15 years or longer. As discussed in Section V.B.1,
approximately 15 billion gallons of corn ethanol production capacity is
currently online, idled or under construction. While some of these
plants/projects are currently on hold due to the economy, we anticipate
that this corn ethanol capacity will come online in the future under
the proposed RFS2 program. And the majority of these plants commenced
construction prior to 2008. We solicit comment, however, on whether
there should be a plant-specific expiration date of 15 years after
commencement of operations for deemed compliant facilities that
commenced construction in 2008 or 2009. Under this sub-option, the
expiration date for such plants would be 15 years from the time the
facility began operation, per registration made by the owner of the
facility.
The option of limiting the exemption period to 15 years or other
specific time period offers certainty to industry for a 15 year period,
and also certainty that at the end of that time period they will be
subject to the 20% GHG reduction threshold. This time period could be
used by facility owners to ensure the facility will ultimately meet the
requirement. Finally, the option ensures that investments made in
equipment to comply with RFS1 requirements are protected with respect
to being fully depreciated for tax purposes.\16\ Furthermore, this
approach is easy to implement, and avoids case-by-case determinations
that can extremely be time-consuming, contentious, and costly for both
industry and EPA. In addition, because the exemption expiration date
would apply to all facilities, this option would provide no incentive
to delay modifications that increase energy efficiency, safety, or
improve environmental performance unlike the option described above
involving case-by-case consideration of reconstruction.
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\16\ Specifically, Table B-2 of IRS Publication 946, ``How To
Depreciate Property'' provides class lives and recovery periods for
use in computing depreciation for asset classes categorized by SIC
codes. Ethanol facilities (which are in SIC 28, Manufacture of
Chemical and Allied Products) is given a class life of 10 years. For
facilities that qualify for Modified Accelerated Cost Recovery
System (MACRS), the period is 7 years.
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(3) Expiration Date of 15 Years for Grandfathered Facilities and
Limitation on Volume
We also seek comment on a hybrid approach in which an expiration
date of 15 years is established for grandfathered and deemed compliant
facilities, but prior to then, the facilities' exemption from the 20%
GHG threshold would be limited to their baseline volumes, as in the
option described in Section III.B.3.c.
(4) ``Significant Production Units'' Are Defined as Facilities
We seek comment on an approach in which ``facility'' would be
defined on the basis of ``significant production units''. For example,
the regulations regarding air toxic emissions for the miscellaneous
organic chemical manufacturing industry (which includes ethanol
manufacturing plants) under NESHAPS (40 CFR 2440(c)) apply to
miscellaneous chemical process units and heat exchangers within a
single facility. This option, therefore, would follow a similar
approach, and treat as new facilities subject to the 20% GHG reduction
requirement any new significant production units.
Defining ``facility'' as a significant production unit would raise
the question of when an increase in volume due to the addition of
specific pieces of equipment should be considered augmenting current
production lines as opposed to being a new production line. We solicit
comment on this approach as well as how the term ``significant
production unit'' would need to be defined in the regulations to avoid
ambiguity. Any incidental increases in volume due to the addition of
pieces of equipment that would not constitute a new ``significant
production unit'' line would continue to be grandfathered, as would
increases in volume associated with changes made to debottleneck the
facility.
(5) Indefinite Grandfathering and No Limitations Placed on Volume
Under our basic option, described in Section III.B.3.c.i, we would
interpret the statutory language to mean that expansions of
grandfathered facilities after enactment of EISA and which expand
volume beyond a plant's inherent capacity are not among those that
qualify for an exemption from the 20% GHG reduction requirement.
Otherwise, a facility that qualifies for grandfathering could be
expanded by any amount, and the additional volume would also receive
protection. We do not believe that this was the intent of the language
in EISA. Nevertheless, we recognize that there are alternative
interpretations of the statute and therefore seek comment on an
alternative that places no limitations on the volume of renewable fuel
from grandfathered or deemed compliant facilities. Under such option,
``new facility'' would be defined solely as a new ``greenfield'' plant.
4. Renewable Biomass With Land Restrictions
As explained in Section III.B.1.a, EISA lists seven types of
feedstock that qualify as ``renewable biomass'':
1. Planted crops and crop residue.
2. Planted trees and tree residue.
3. Animal waste material and animal byproducts.
4. Slash and pre-commercial thinnings.
5. Biomass obtained from the vicinity of buildings at risk from
wildfire.
6. Algae.
7. Separated yard or food waste.
EISA limits not only the types of feedstocks that can be used to
make renewable fuel, but also the land that several of these renewable
fuel feedstocks may come from. Specifically, EISA's definition of
renewable biomass incorporates land restrictions for planted crops and
crop residue, planted trees and tree residue, slash and pre-commercial
thinnings, and biomass from wildfire areas. EISA does not prohibit the
production of renewable fuel feedstock that does not meet the
definition of renewable biomass, nor does it prohibit the production of
renewable fuel from feedstock that does not meet the definition of
renewable biomass. It does, however, prohibit the generation of RINs
for renewable fuel made from feedstock that does not meet the
definition of renewable biomass, which includes not meeting the
associated land restrictions. The following sections discuss the
challenges of implementing the land restrictions contained in the
definition of renewable biomass and propose approaches for establishing
a workable implementation scheme.
a. Definitions of Terms
EISA's descriptions of four feedstock types noted above--planted
crops and crop residue, planted trees and tree residue, slash and pre-
commercial thinnings, and biomass from wildfire areas--contain terms
that can be interpreted in multiple ways. The following sections
discuss our proposed interpretations for many of the terms contained in
EISA's definition of renewable biomass. In developing this proposal, we
consulted many sources, including the USDA, as well as stakeholder
groups, in order to
[[Page 24931]]
determine the range of possible interpretations for these different
terms. We have made every attempt to define these terms as consistently
with USDA and industry standards as possible, while keeping them
workable for purposes of program implementation. We seek comment on our
proposed definitions of important terms in the following sections.
i. Planted Crops and Crop Residue
The first type of renewable biomass described in EISA is planted
crops and crop residue harvested from agricultural land cleared or
cultivated at any time prior to December 19, 2007, that is either
actively managed or fallow, and nonforested. We propose to interpret
the term ``planted crops'' to include all annual or perennial
agricultural crops that may be used as feedstock for renewable fuel,
such as grains, oilseeds, and sugarcane, as well as energy crops, such
as switchgrass, prairie grass, and other species, providing that they
were intentionally applied to the ground by humans either by direct
application as seed or nursery stock, or through intentional natural
seeding by mature plants left undisturbed for that purpose. Many energy
crops that could be used for cellulosic biofuel production, especially
perennial cover plants, are currently grown in the U.S. without
significant agronomic inputs such as fertilizer, pesticides, or other
chemical treatment. These crops may be introduced or indigenous to the
area in which they grow, and may have been originally planted decades
ago. We propose to include this type of vegetation as a planted crop
with the recognition that it may include some plants that were
intentionally naturally generated, i.e., resulted from natural seeding
from existing plants, and not planted through direct human
intervention. We believe that given the increasing importance under
RFS2 of biofuels produced from cellulosic feedstocks, such as
switchgrass and other grasses, such a definition is appropriate. We
note that because EISA contains specific provisions for planted trees
and tree residue from tree plantations, we propose that the definition
of planted crops in EISA exclude planted trees, even if they may be
considered planted crops under some circumstances.
We further propose that ``crop residue'' be limited to the residue
left over from the harvesting of planted crops, such as corn stover and
sugarcane bagasse. However, we seek comment on an alternative
interpretation that would include as crop residue biomass from
agricultural land removed for purposes of invasive species control or
fire management. In that context ``crop residue'' would include any
biomass removed from agricultural land that facilitates crop
management, whether or not the crop itself is part of the residue.
Our proposed regulations would restrict planted crops and crop
residue to that harvested from existing agricultural land. With respect
to what land would qualify as agricultural land, we first turned to the
mutually exclusive categories of land defined by USDA's Natural
Resources Conservation Service (NRCS) in its annual Natural Resources
Inventory (NRI), a statistical survey designed to estimate natural
resource conditions and trends on non-federal U.S. lands.\17\ The
categories used in the NRI are cropland, pastureland, rangeland, forest
land, Conservation Reserve Program (CRP) land, federal land, developed
land, and ``other rural land.'' We have chosen to include in our
proposed definition of agricultural land three of these land
categories--cropland, pastureland, and CRP land. Using the NRI
descriptions of these land types as models, we developed definitions
for these land types for this proposal.
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\17\ Natural Resource Conservation Service, USDA, ``Natural
Resources Inventory 2003 Annual NRI,'' February 2007. Available at
http://www.nrcs.usda.gov/technical/NRI/2003/Landuse-mrb.pdf.
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We propose to define cropland as land used for the production of
crops for harvest, including cultivated cropland for row crops or
close-grown crops and non-cultivated cropland for horticultural crops.
Corn, wheat, barley, and soybeans are renewable fuel feedstocks that
would be grown on cropland. We propose to define pastureland as land
managed primarily for the production of indigenous or introduced forage
plants for livestock grazing or hay production, and to prevent
succession to other plant types. Under this proposed definition, land
would qualify as pastureland if it is maintained for grazing or hay
production and not allowed to develop greater ecological diversity.
Switchgrass is one example of a renewable fuel feedstock that could be
grown on pastureland.
We also propose that CRP land be counted as ``agricultural land''
under RFS2. The CRP is administered by USDA's Farm Service Agency and
is designed to promote restoration of environmentally sensitive lands
by offering annual rental payments in return for removing land from
cultivation over a period of several years. To qualify for the CRP,
land had to have been used for agricultural production for at least
three years prior to entering the program. For this reason, we believe
it is appropriate to propose that CRP land be included under the rubric
of agricultural land.
In addition, we seek comment on whether rangeland should be
included as agricultural land under RFS2. Rangeland is land on which
the indigenous or introduced vegetation is predominantly grasses,
grass-like plants, forbs or shrubs and which--unlike cropland or
pastureland--is predominantly managed as a natural ecosystem. Given the
relative lower degree of management of such lands, it is questionable
whether any rangeland should qualify as ``actively managed'' under EISA
(a general discussion on our proposed interpretation of the term
``actively managed'' is presented later in this section). On the other
hand, we understand that there is frequently some degree of management
on such lands, such as controlling invasive species, managing grazing
rates, fencing, etc.
Therefore, we believe that there may be merit in allowing planted
crops and crop residue from rangeland to qualify as renewable biomass
under this program. This would allow, for example, existing switchgrass
or native grasses on rangeland to be used for renewable fuel production
that qualifies for RIN generation under this program. However, we are
not proposing to include rangeland as agricultural land due to our own
implementation concerns as well as issues raised by stakeholders over
the potential for providing any incentive for increased crop production
in rangeland areas. We seek comment on the issue and on the points
raised in the following discussion.
Allowing rangeland to qualify as agricultural land under RFS2 would
make millions of acres of additional non-cropland, non-forested land
qualify for renewable fuel feedstock production in the U.S. This
additional land could be important to support future expansion of
dedicated energy crops, such as switchgrass and tall prairie grass,
which currently grow or could grow on such lands. The availability of
rangeland could alleviate some of the competition on cropland and
pastureland for space to grow crops for biofuel feedstocks, thereby
allowing continued growth of food crops on land best suited for that
specific purpose. It would also provide rangeland owners with the
potential for increased revenues from their lands by producing
feedstocks for renewable fuel, and decrease the pressure for such lands
to be converted to cropland for food crop production.
[[Page 24932]]
However, we recognize that rangeland is a term that can be used to
describe a wide variety of ecosystems, including certain grasslands,
savannas, wetlands, deserts, and even tundra. These types of ecosystems
represent land that at best could serve only marginally well for
producing renewable fuel feedstocks, and at worst could suffer
significantly if intensive agricultural practices were imposed upon
them for purposes of producing crops. We also recognize that if we were
to include rangeland as agricultural land under RFS2, there is a risk
that some rangeland, including native grasslands and shrublands, could
be converted to produce monoculture crops. We raise these concerns for
two reasons. First, certain rangeland cannot be used sustainably for
agricultural crop production, and any such short-term use could
seriously diminish the long-term potential of these lands to be used
for less-intensive forage production or even to return to their
previous ecological state. Second, conversion of relatively undisturbed
rangeland to the production of annual crops could in some cases result
in large releases of GHGs that have been stored in the soil. EPA
believes that Congress enacted the renewable biomass definition in part
to minimize GHG releases from land conversion, a goal that could be
undermined by conversion of rangeland to intensive crop production
under RFS2. On the other hand, it may be argued that while GHGs would
be emitted initially, planting dedicated energy crops rather than food
crops on such land could yield more positive than negative results over
time. Such could be the case if the alternative were to grow energy
crops on cropland, consequently displacing food crops to other lands,
either in the U.S. or abroad. This displacement could lead to overall
higher direct and indirect GHG emissions. EPA solicits comment on the
potential GHG effects if rangeland were included as eligible
agricultural land under RFS2. We are especially interested in data that
could help us to quantify such impacts.
While enforcement of the overall renewable biomass provisions under
the final RFS2 program is expected to be challenging, it is possible
that including rangeland as qualifying agricultural land under the RFS2
program would increase enforcement complexity. As discussed later in
this section, in order to qualify as renewable biomass under RFS2,
agricultural products must come from agricultural land that was cleared
or cultivated at any time prior to enactment of EISA, and either
actively managed or fallow, and nonforested. We believe that evidence
of past intensive use and management of rangeland may be considerably
more rare, and considerably less definitive, than for other types of
agricultural land. In addition, given the continuous, open nature of
some rangeland, there would likely be difficulty in identifying the
precise boundaries of a parcel of qualifying rangeland. EPA seeks
comment on these issues.
We thus seek comment on whether or not we should include rangeland
in the definition of ``existing agricultural land'' in the final RFS2
program, as well as comment on whether or not the benefits of including
rangeland exceed the disadvantages. We also seek comment on how best to
define rangeland, and whether we can define rangeland in a meaningful
way such that sensitive ecosystems that may generally be described as
rangeland can be protected from cultivation for renewable fuel
feedstock production.
Furthermore, EPA solicits comment on an alternative option that
would include rangeland as agricultural land, but that would interpret
the EISA ``actively managed'' criterion in the renewable biomass
definition (again, discussed later in this section) to limit the types
of planted crops or crop residues from specific parcels of land that
can qualify as renewable biomass by reference to the type of management
(cropland, pastureland, or rangeland) being practiced on the date EISA
was enacted. For example, if at some point in the future corn or other
row crops are grown on land that was pastureland or rangeland when EISA
was enacted, such row crops would not qualify as renewable biomass
under RFS2. This approach could thus reduce the incentives for
pastureland and rangeland owners to convert their land to cropland. We
believe that this approach could have less environmental harm than
allowing unrestricted use of qualifying rangeland for the production of
crops for renewable fuel production.
While our proposed implementation approach and alternatives are
presented later in this section, it is important to note here that the
principal drawback to this alternative option involves its
implementation and enforcement. This approach would require that land
types (again, cropland, pastureland, or rangeland) be identified as of
the date of EISA enactment in order to determine which feedstocks grown
on such land would qualify as renewable biomass. In practical terms,
such an approach may mean, for example, that a renewable fuel producer
would need to be able to identify not only whether a given shipment of
corn was grown on agricultural land cleared or cultivated prior to
enactment of EISA, but also that the land was not previously
pastureland or rangeland that had been converted to cropland after
enactment of EISA. If it was, it would not qualify as renewable
biomass. We are concerned that adding this additional feedstock
verification criterion to those already contained in this proposal
could render the program unworkable and unenforceable. However, we
invite comment on this option, and specifically request comment on how
this option could be implemented in a workable and enforceable manner.
In keeping with the statutory definition for renewable biomass, we
propose to include in our definition of existing agricultural land the
requirement that the land was cleared or cultivated prior to December
19, 2007, and that, since December 19, 2007, it has been continuously
actively managed (as agricultural land) or fallow, and nonforested. We
believe the language ``cleared or cultivated at any time'' prior to
December 19, 2007, describes most cultivable land in the U.S., since so
much of the country's native forests and grasslands were cleared in the
17th, 18th, and 19th centuries, if not before, for agriculture. We
further believe that land that was cropland, pastureland, or CRP land
on December 19, 2007, would automatically satisfy this particular
criterion, and that therefore it is not of significant concern from an
implementation or enforcement perspective.
In the event that we were to include rangeland as agricultural land
under the final RFS2 program, satisfying the ``cleared or cultivated''
criterion could pose significant challenges. Some rangeland has never
been cleared or cultivated, or may have been cleared or cultivated
prior to December 19, 2007, but no evidence exists to confirm this.
Therefore, we could not assume that it would necessarily meet the
``cleared or cultivated'' criterion. For instance, grasslands in the
Midwest and West that during the Dust Bowl of the 1930s had been used
for cultivation could meet this criterion, but other western grasslands
and prairies used for cattle grazing may not. We seek comment on how
best to verify that rangeland to be used for renewable fuel feedstock
production was cleared or cultivated at some point prior to December
2007. We also seek comment on whether the challenge associated with
applying this criterion to rangeland is sufficient (alone or combined
with the concerns raised earlier about the inclusion of rangeland in
the definition of agricultural land) to exclude rangeland
[[Page 24933]]
from the final definition of agricultural land.
We believe that the more restrictive, and therefore more important,
criteria is whether agricultural land is actively managed or fallow,
and nonforested, per the statutory language. We propose to interpret
the phrase ``that is actively managed or fallow, and nonforested'' as
meaning that land must have been actively managed or fallow, and
nonforested, on December 19, 2007, and continuously thereafter in order
to qualify for renewable biomass production. We believe this
interpretation of the legislative language is reasonable and
appropriate for the following reason. The EISA language uses the
present tense (``is actively managed * * *'') rather than the past
tense to describe qualifying agricultural land. We interpret this
language to mean that at the time the planted crops or crop residue are
harvested (i.e., now or at some time in the future), the land from
which they come must be actively managed or fallow, and nonforested.
However, assuming that the land was cleared or cultivated at some point
in time, then any land converted to agricultural land after December
19, 2007, and used to produce crops or crop residue would inherently
meet the definition of ``is actively managed or fallow, and
nonforested,'' and the EISA land restriction for planted crops and crop
residue would have little meaning (except in cases where it could be
established that the land in question had never been cleared or
cultivated). We believe that in order for this provision to have
meaning, we must require that agricultural land remain ``continuously''
either actively managed or fallow, and nonforested, since December 19,
2007. In this way, the upper bound on acreage that qualifies for
planted crop and crop residue production under RFS2 would be limited to
existing agricultural land--cropland, pastureland, or CRP land--as of
December 19, 2007, and the phrase ``is actively managed or fallow, and
nonforested'' would be interpreted in a meaningful way.
We propose that ``actively managed'' would mean managed for a
predetermined outcome as evidenced by any of the following: sales
records for planted crops, crop residue, or livestock; purchasing
records for land treatments such as fertilizer, weed control, or
reseeding; a written management plan for agricultural purposes;
documentation of participation in an agricultural program sponsored by
a Federal, state or local government agency; or documentation of land
management in accordance with an agricultural certification program.
Examples of government programs or product certification programs that
would indicate active agricultural land management include USDA's
certified organic program or the Federal Crop Insurance program.
We realize that it may be difficult to conclude that certain land
has been actively managed continuously since December 2007 based solely
on the existence of receipts for fertilizer or seed. However, we have
included sales and purchasing records in the list of written
documentation that could be used to indicate active management due to
the fact that there may be qualifying land that is not registered with
any formal agricultural program, for which the owner does not receive
government benefits, and for which no written management plan exists
(or existed as of December 2007). We believe this may be the case
especially for pastureland from which no crops are harvested or sold.
Other evidence that could be used regarding the consistent management
of pastureland since December 2007 are records associated with the sale
of livestock that grazed on the land. We seek comment on our proposal
to include relevant records of sales and purchasing as adequate
documentation to prove that land was actively managed since December
2007 and whether there may be other records, such as tax or insurance
records, which could satisfy this requirement more effectively.
The term ``fallow'' is generally used to describe cultivated land
taken out of production for a finite period of time. We believe it may
be argued that fallow land is actively managed land because there is a
clear purpose or goal for taking the land out of production for a
period of time (e.g., to conserve soil moisture). Nonetheless, because
the EISA language clearly identifies a difference between actively
managed agricultural land and fallow agricultural land, we propose to
define fallow to mean agricultural land that is intentionally left idle
to regenerate for future agricultural purposes, with no seeding or
planting, harvesting, mowing, or treatment during the fallow period.
While fallow agricultural land is characterized by a lack of activity
on the land, we believe that the decision to let land lie fallow is
made deliberately and intentionally by a land owner or farmer such that
there should be documentation of such intent. We seek comment on this
assumption and on whether there are other means of verifying whether
land was fallow, particularly as of December 2007. We also seek comment
on whether we should specify in the regulations a time period after
which land that is not actively managed for agricultural purposes
should be considered to have been abandoned for agriculture (and not
eligible for renewable biomass production under RFS2), as opposed to
being left fallow. If specifying such a time limit is appropriate, we
seek comment on what the time period should be, and if there should be
a distinction between allowable fallow periods for different types of
agricultural land.
Finally, in order to define the term ``nonforested,'' we first
propose to define the term ``forestland'' as generally undeveloped land
covering a minimum area of 1 acre upon which the predominant vegetative
cover is trees, including land that formerly had such tree cover and
that will be regenerated. We are also proposing that forestland would
not include tree plantations. Under this proposal, ``nonforested'' land
would be land that is not forestland. We believe this definition is
sufficient to make distinctions between forestland and land that is
considered nonforested in the field. However, we seek comment on
whether we should incorporate into our definition of forestland more
quantitative descriptors, such as a minimum percentage of canopy cover
or minimum or maximum tree height, to help clarify what would be
considered forestland. For example, the NRI definition of forestland
includes a minimum of twenty-five percent canopy cover. We also seek
comment on whether the one-acre minimum size designation is
appropriate.
ii. Planted Trees and Tree Residue
The definition of renewable biomass in EISA includes planted trees
and tree residue from actively managed tree plantations on non-federal
land cleared at any time prior to December 19, 2007, including land
belonging to an Indian tribe or an Indian individual, that is held in
trust by the United States or subject to a restriction against
alienation imposed by the United States. We propose to define the term
``planted trees'' to include not only trees that were established by
human intervention such as planting saplings and artificial seeding,
but also trees established from natural seeding by mature trees left
undisturbed for such a purpose. We understand that, depending on the
particular conditions at a plantation, certain trees in a stand may be
harvested, while others are maintained, for the express purpose of
naturally regenerating new trees. We believe that trees established in
such a fashion, and which meet the conditions for planted trees in
every other way, should not be
[[Page 24934]]
excluded from qualifying as renewable biomass under RFS2.
Rather than using the term ``tree residue,'' we propose to use the
term ``slash'' in our regulations as a more descriptive, but otherwise
synonymous, term. According to the Dictionary of Forestry (1998, p.
168), slash is ``the residue, e.g., treetops and branches, left on the
ground after logging or accumulating as a result of a storm, fire,
girdling, or delimbing.'' We believe that this substitution will
simplify our regulations, since paragraph (iv) of the EISA definition
of renewable biomass also uses the term ``slash.'' Furthermore, the
term ``slash'' is a common term that has a specific meaning to
industry. As noted earlier, we have attempted to define terms in RFS2
using existing and commonly understood definitions to the extent
possible. The term ``slash'' is more descriptive than ``tree residue,''
and yet in practice means the same thing, so we are proposing to use it
rather than ``tree residue.'' We also propose to clarify that slash can
include tree bark and can be the result of any natural disaster,
including flooding.
In concert with our proposed definition for ``planted trees,'' we
propose to define a ``tree plantation'' as a stand of no fewer than 100
planted trees of similar age and comprising one or two tree species, or
an area managed for growth of such trees covering a minimum of 1 acre.
Given that only trees from a tree plantation may be used as renewable
biomass under RFS2, we believe that the definition should be clear and
easily applied in the field. We recognize that this proposed definition
is more specific than the Dictionary of Forestry's definition of ``tree
plantation,'' which is ``a stand composed primarily of trees
established by planting or artificial seeding.'' We seek comment on all
aspects of our proposed definition of tree plantation.
We also propose to apply the same management restrictions on tree
plantations as on agricultural land and to interpret the EISA language
as requiring that to qualify for renewable biomass production under
RFS2, a tree plantation must have been cleared at any time prior to
December 19, 2007, and continuously actively managed since December 19,
2007. Similar to our proposal for actively managed agricultural land,
we propose to define the term ``actively managed'' in the context of
tree plantations as managed for a predetermined outcome as evidenced by
any of the following: Sales records for planted trees or slash;
purchasing records for seeds, seedlings, or other nursery stock; a
written management plan for silvicultural purposes; documentation of
participation in a silvicultural program sponsored by a Federal, state
or local government agency; or documentation of land management in
accordance with an agricultural or silvicultural product certification
program. Silvicultural programs such as those of the Forest Stewardship
Council, the Sustainable Forestry Initiative, the American Tree Farm
System, or USDA are examples of the types of programs that could
indicate actively managed tree plantations.
iii. Slash and Pre-Commercial Thinnings
The EISA definition of renewable biomass includes slash and pre-
commercial thinnings from non-federal forestlands, including
forestlands belonging to an Indian tribe or an Indian individual, that
are held in trust by the United States or subject to a restriction
against alienation imposed by the United States. It excludes slash and
pre-commercial thinnings from forests or forestlands that are
ecological communities with a global or State ranking of critically
imperiled, imperiled, or rare pursuant to a State Natural Heritage
Program, old growth forest, or late successional forest.
As described in Sec. III.B.4.a.i of this preamble, our proposed
definition of ``forestland'' is generally undeveloped land covering a
minimum area of 1 acre upon which the primary vegetative species are
trees, including land that formerly had such tree cover and that will
be regenerated. Also as noted in Sec. III.B.4.a.ii of this preamble, we
propose to adopt the definition of slash listed in the Dictionary of
Forestry. As for ``pre-commercial thinnings,'' the Dictionary of
Forestry defines the act of such thinning as ``the removal of trees not
for immediate financial return but to reduce stocking to concentrate
growth on the more desirable trees.'' \18\ Because what may now be
considered pre-commercial may eventually be saleable as renewable fuel
feedstock, we propose not to include any reference to ``financial
return'' in our definition, but rather to define pre-commercial
thinnings as those trees removed from a stand of trees in order to
reduce stocking to concentrate growth on more desirable trees. We
propose to include diseased trees in the definition of pre-commercial
thinnings due to the fact that they can threaten the integrity of an
otherwise healthy stand of trees, and their removal can be viewed as
reducing stocking to promote the growth of more desirable trees. We
seek comment on whether our definition of pre-commercial thinnings
should include a maximum diameter and, if so, what the appropriate
maximum diameter should be.
---------------------------------------------------------------------------
\18\ Helms, John, ed. ``The Dictionary of Forestry.'' Bethesda,
MD: Society of American Foresters, 2003.
---------------------------------------------------------------------------
We understand that the State Natural Heritage Programs referred to
in EISA are those comprising a network associated with NatureServe, a
non-profit conservation and research organization. The network includes
local programs in each of the 50 United States, other U.S. territories
and regions including the Navajo Nation and Tennessee Valley Authority,
eleven Canadian provinces and territories, and eleven Latin American
countries. Individual Natural Heritage Programs collect, analyze, and
distribute scientific information about the biological diversity found
within their jurisdictions. As part of their activities, these programs
survey and apply NatureServe's rankings, such as critically imperiled
(S1), imperiled (S2), and rare (S3) to species and ecological
communities within their respective borders. NatureServe meanwhile uses
data gathered by these Natural Heritage Programs to apply its global
rankings, such as critically imperiled (G1), imperiled (G2), or
vulnerable (the equivalent of the term ``rare,'' or G3), to species and
ecological communities found in multiple States or territories. We
propose to prohibit slash and pre-commercial thinnings from all forest
ecological communities with global or State rankings of critically
imperiled, imperiled, or vulnerable (``rare'' in the case of State
rankings) from being used for renewable fuel for which RINs may be
generated under RFS2. We seek comment on our interpretation that the
statutory language implies including global rankings determined by
NatureServe, including the ranking of vulnerable (G3), in the land
restrictions under RFS2 since State Natural Heritage Programs, which
were explicitly referenced in EISA, do not establish global rankings.
The various state-level Natural Heritage Programs in the U.S. and
abroad differ in organizational affiliation, with some operated as
agencies of state or provincial government and others residing within
universities or non-profit organizations. According to the NatureServe
Web site, ``consistent standards for collecting and managing data allow
information from different programs to be shared and combined
regionally, nationally, and internationally. The nearly 800 staff from
across the network are experts in their fields, and include some of the
most knowledgeable field biologists and
[[Page 24935]]
conservation planners in their regions.'' Different Natural Heritage
Programs have different processes for initiating and performing surveys
of ecological communities. In many cases, the programs respond to
requests for environmental reviews or surveys from parties interested
in specific locations, oftentimes for a fee. They do not make available
for public consumption detailed information on the location of a ranked
ecological community in some cases to protect the communities
themselves and in other cases to protect private property interests.
Additionally, the datasets maintained by different Natural Heritage
Programs may not completely represent all of the vulnerable ecological
communities in their respective States or territories simply due to the
fact that surveys have not been performed for all areas.
NatureServe, however, interacts with each of the State Natural
Heritage Programs to update their central database to include each
State program's ecological community rankings. We propose to use data
compiled by NatureServe and published in a special report to identify
``ecologically sensitive forestland.'' The report would list all forest
ecological communities in the U.S. with a global ranking of G1, G2, or
G3, or with a State ranking of S1, S2, or S3, and would include
descriptions of the key geographic and biologic attributes of the
referenced ecological community. The document would be incorporated by
reference into the definition of renewable biomass in the final RFS2
regulations, and the effect would be to identify specific ecological
communities from which slash and pre-commercial thinnings could not be
used as feedstock for the production of renewable fuel that would
qualify for RINs under RFS2. In the future, it may be necessary to
update this list as appropriate through notice and comment rulemaking.
We will place a draft version of this document in the docket for
the proposed rule as soon as it is available. EPA solicits comment both
on this general incorporation-by-reference approach and on each
individual listing in the document. We also seek comment on whether EPA
should include in the document forest ecological communities outside of
the 50 United States (such as in Canada or Latin American countries)
that have natural heritage rankings of G1, G2, or G3 or S1, S2, or S3.
In addition, we request comment on other ways that EPA may be able to
provide the protections that Congress intended for important ecological
communities with state-level rankings pursuant to a State Natural
Heritage Program.
To complete the definition of ``ecologically sensitive
forestland,'' we propose to include old growth and late successional
forestland which is characterized by trees at least 200 years old.\19\
We seek comment on this definition, including the proposed 200-year
tree age, on whether we should specify a process for determining when a
forest is ``characterized by'' trees of this or another age, and on
other ways to identify old growth or late successional forestland.
---------------------------------------------------------------------------
\19\ Old-growth forest is defined in the Dictionary of Forestry
as ``the (usually) late successional stage of forest development.
Note: Old-growth forests are defined in many ways; generally,
structural characteristics used to describe old-growth forests
include (a) live trees: Number and minimum size of both seral and
climax dominants, (b) canopy conditions: Commonly including
multilayering, (c) snags: Minimum number of specific size, and (d)
down logs and coarse woody debris: Minimum tonnage and numbers of
pieces of specific size. Note: Old-growth forests generally contain
trees that are large for their species and site and sometimes
decadent (overmature) with broken tops, often a variety of trees
sizes, large snags and logs, and a developed and often patchy
understory * * *.''
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iv. Biomass Obtained From Certain Areas at Risk From Wildfire
The EISA definition of renewable biomass includes biomass obtained
from the immediate vicinity of buildings and other areas regularly
occupied by people, or of public infrastructure, at risk from wildfire.
We propose to clarify in the regulations that ``biomass'' is organic
matter that is available on a renewable or recurring basis, and that it
must be obtained from within 200 feet of buildings, campgrounds, and
other areas regularly occupied by people, or of public infrastructure,
such as utility corridors, bridges, and roadways, in areas at risk of
wildfire. We propose to define ``areas at risk of wildfire'' as areas
located within--or within one mile of--forestland, tree plantations, or
any other generally undeveloped tract of land that is at least one acre
in size with substantial vegetative cover.
It is our understanding that 100 to 200 feet is the minimum
distance recommended for clearing trees and brush away from homes and
other property in certain wildfire-prone areas, depending on slope and
vegetation.\20\ We propose that under RFS2, the term ``immediate
vicinity'' would mean within 200 feet of a given structure or area, but
we seek comment on the appropriateness of limiting the distance to
within 100 feet.
---------------------------------------------------------------------------
\20\ See Cohen, Jack. ``Reducing the Wildland Fire Threat to
Homes: Where and How Much?'' USDA Forest Service Gen.Tech.Rep. PSW-
GTR-173. 1999. See also U.S. Federal Emergency Management Agency
(FEMA) Web site http://www.fema.gov/hazard/wildfire/index.shtm.
---------------------------------------------------------------------------
A great deal of work has been done to identify communities and
areas on the landscape in the vicinity of public lands that are at risk
of wildfire by States in cooperation and consultation with the U.S.
Forest Service, Bureau of Land Management, and other federal, State,
and local agencies and tribes. In order to take advantage of this work,
we seek comment on two possible implementation alternatives. The first
alternative would incorporate into our definition of ``areas at risk of
wildfire'' any communities identified as ``communities at risk''
through a process defined within the ``Field Guidance--Identifying and
Prioritizing Communities at Risk'' (National Association of State
Foresters, June 2003) and covered by a community wildfire protection
plan (CWPP) developed in accordance with ``Preparing a Community
Wildfire Protection Plan--A Handbook for Wildland-Urban Interface
Communities'' (Society of American Foresters, March 2004) and certified
by a State Forester or equivalent. We believe that it may make sense to
include communities with CWPPs in the definition of ``areas at risk of
wildfire'' since they represent specific areas around the U.S. that are
identified and agreed upon through a public process that includes local
and state representatives, federal agencies, and stakeholders.
Additionally, CWPP guidelines indicate that normally three entities
must mutually agree to the contents of the CWPPs: The applicable local
government, the local fire department or departments, and the state
entity responsible for forest management (State Forester or
equivalent). As of June 2008, there were roughly 52,000 total
``communities at risk'' and 5,000 ``communities at risk'' covered by a
CWPP.
We seek comment on incorporating by reference into the final RFS2
regulations a list of ``communities at risk'' with an approved CWPP.
Similar to the document proposed for Natural Heritage Rankings, this
document would be incorporated by reference into the definition of
``areas at risk of wildfire'' in the final RFS2 regulations. Because
this list does not currently exist, EPA would be required to seek data
from each State in order to assemble the document. The effect of this
incorporation by reference would be to identify specific areas in the
U.S. at risk of wildfire and from which biomass obtained from the
immediate vicinity of buildings and other areas regularly occupied by
people, or of public infrastructure, could be easily identified
[[Page 24936]]
and documented as renewable biomass. In the future, it may be necessary
to update this list as appropriate through notice and comment
rulemaking.
The second implementation approach on which we seek comment would
incorporate into our definition of ``areas at risk of wildfire'' any
areas identified as wildland urban interface (WUI) land, or land in
which houses meet wildland vegetation or are mixed with vegetation. The
concept of the WUI was established as part of the Healthy Forests
Restoration Act (Pub. L. 108-148) which provided a means for
prioritizing, planning, and executing hazardous fuels reduction
projects on federal lands. SILVIS Lab, in the Department of Forest
Ecology and Management and the University of Wisconsin, Madison, has,
with funding provided by the U.S. Forest Service, mapped WUI lands
based on data from the 2000 U.S. Census and U.S. Geological Survey
National Land Cover Data.\21\ We seek comment on whether and how best
to make use of this WUI map and data to help implement the land
restrictions for biomass obtained from areas at risk of wildfire under
RFS2.
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\21\ See http://silvis.forest.wisc.edu/projects/US_WUI_2000.asp.
---------------------------------------------------------------------------
b. Issues Related to Implementation and Enforceability
Incorporating the new definition of renewable biomass into the RFS2
program raises issues that we did not have to consider when designing
the RFS1 program. Under RFS1, the source of a renewable fuel feedstock
was not a central concern, and it was a relatively straightforward
matter to require all fuel made from specified renewable feedstocks to
be assigned RINs. However, with the terms ``renewable fuel'' and
``renewable biomass'' being defined differently under EISA, we must
consider potential issues related to implementation and enforcement to
ensure that renewable fuel for which RINs are generated is produced
from qualifying renewable biomass.
Our proposed approach to the treatment of renewable biomass under
RFS2 is intended to define the conditions under which RINs can be
generated as well as the conditions under which renewable fuel can be
produced or imported without RINs. Both of these areas are described in
more detail below.
i. Ensuring That RINs Are Generated Only for Fuels Made From Renewable
Biomass
The effect of adding EISA's definition of renewable biomass to the
RFS program is to ensure that renewable fuels are only allowed to
participate in the program if the feedstocks from which they were made
come from certain types of land. In the context of our regulatory
program, this means that RINs could only be generated if it can be
established that the feedstock from which the fuel was made came from
these types of lands. Otherwise, no RINs could be generated to
represent the renewable fuel produced or imported.
We have considered the possibility that land restrictions contained
within the definition of renewable biomass may not, in practice, result
in a significant change in agricultural practices. For example, a
farmer wishing to expand his production by cutting forested land could
grow feedstock for renewable fuel on his existing agricultural land and
move production for food, animal feed, and fiber production to newly
cultivated land. While the EISA language is fairly clear about what
lands may be used for harvesting renewable fuel feedstocks, it does not
specifically address the potential for switching non-feedstock crops to
new lands. Our proposed options recognize the potential for this
behavior but do not attempt to prohibit it as we believe doing so would
be beyond our mandate under EISA. EPA believes that Congress would have
specifically directed EPA to regulate this practice if they intended
EPA to do so.
Another major issue we have considered is the treatment of
domestically produced renewable fuel feedstocks versus imported
feedstocks and imported renewable fuel, since the new EISA language
does not distinguish between domestic renewable fuel feedstocks and
renewable fuel and feedstocks that come from abroad. Under RFS1, RINs
must be generated for imported renewable fuel by the renewable fuel
importer. Foreign renewable fuel producers may not participate as
producers in the program (i.e., may not generate RINs for their fuel)
unless they produce cellulosic biomass or waste-derived ethanol and
register with EPA. Because RFS1 does not define renewable fuel by its
source, assigning RINs to imported renewable fuel under RFS1 is a
straightforward responsibility of the importer.
However, under RFS2, ensuring that the feedstock used to produce
imported renewable fuel meets the definition of renewable biomass
presents additional challenges to designing a program that can apply to
both domestic and imported renewable fuel. The options contained in
today's proposal attempt to address this additional constraint, as
discussed in Section III.B.4.d of this preamble.
ii. Ensuring That RINs Are Generated for All Qualifying Renewable Fuel
Under RFS1, virtually all renewable fuel is required to be assigned
a RIN by the producer or importer. This requirement was developed and
finalized in the RFS1 rulemaking in order to address stakeholder
concerns, particularly from obligated parties, that the number of
available RINs should reflect the total volume of renewable fuel used
in the transportation sector in the U.S. and facilitate program
compliance. The only circumstances under which a batch of fuel is not
assigned a RIN in RFS1 is if the feedstock used to produce the fuel is
not among those listed in the regulatory definition of renewable fuel
at Sec. 80.1101(d), the producer or importer of the fuel produces or
imports less than 10,000 gallons per year, or the fuel is produced and
used for off-road or other non-motor vehicle purposes. As a result, we
believe that almost all renewable fuel produced or imported into the
U.S. is assigned RINs under the RFS1 program, and thus the number of
RINs available to obligated parties represents as accurately as
possible the volume of renewable fuel being used in the U.S.
transportation sector.
EISA has dramatically increased the mandated volumes of renewable
fuel that obligated parties must ensure are produced and used in the
U.S. At the same time, EISA makes it more difficult for renewable fuel
producers to demonstrate that they have fuel that qualifies for RIN
generation by restricting qualifying renewable fuel to that made from
``renewable biomass,'' defined to include restrictions on the types of
land from which feedstocks may be harvested, as discussed in this
section. The inclusion of such land restrictions under RFS2 may mean
that, in some situations, a renewable fuel producer would prefer to
forgo the benefits of RIN generation to avoid the cost and difficulty
of ensuring that its feedstocks qualify for RIN generation. If a
sufficient number of renewable fuel producers acted in this way, it
could lead to a situation in which not all qualifying fuel is assigned
RINs, thus resulting in a short RIN market that could force obligated
parties into non-compliance. Another possible outcome would be that the
demand for and price of RINs would increase significantly, making
compliance by obligated parties more costly and difficult than
necessary and raising prices for consumers.
In order to avoid situations in which obligated parties cannot
comply with
[[Page 24937]]
their annual RVOs and the volume mandates in EISA are not met, or
instances where the requirements are met but at an inflated price, we
believe that our proposal should ensure that RINs are generated for all
fuel made from feedstock that meets the definition of renewable biomass
and which meets the GHG emissions reduction thresholds set out in EISA.
This would require eliminating any incentive for renewable fuel
producers to avoid ascertaining where their feedstocks come from. As
described in Section III.B.4.d below, we propose to require a
demonstration of the type of land used to produce any feedstock used in
the production of renewable fuel, regardless of whether RINs are
generated or not, and to require that RINs be generated for all
qualifying fuel.
However, we also seek comment on an alternative approach wherein a
renewable fuel producer would not be required to make any demonstration
with regard to the origin of feedstocks used in fuel production if the
fuel producer were not generating RINs. In this situation, we would
rely on the price of RINs in the market to encourage renewable fuel
producers to generate RINs where possible. This approach would have the
advantage of lessening the regulatory burden for renewable fuel
producers using feedstock that is not renewable biomass, and would
generally simplify the regulations relating to implementation of the
renewable biomass definition. The disadvantage to this approach, as
discussed above, would be the increased potential for a RIN shortage
caused by renewable fuel producers choosing not to generate RINs for
qualifying renewable fuel and a concurrent increase in the price of
RINs that do exist. Under such circumstances, it is likely that some
obligated parties could not acquire sufficient RINs for compliance
purposes, while others could comply but at an inflated cost.
A further step that we could take to streamline not just the
implementation of the renewable biomass definition, but also the
tracking and trading of RINs, would be to remove the restriction
established under the RFS1 rule requiring that RINs be assigned to
batches of renewable fuel and transferred with those batches. Instead,
renewable fuel producers could sell RINs (with a K code of 2 rather
than 1) separately from volumes of renewable fuel. While this
alternative approach could potentially place obligated parties at
greater risk of market manipulation by renewable fuel producers, it
could also provide a greater incentive for producers to demonstrate
that the renewable biomass definition has been met for their
feedstocks. That is, by having the flexibility to sell RINs independent
from volume, producers could potentially command higher prices for
those RINs. This would make RINS more valuable to them, and provide an
incentive to generate as many RINs as possible. As a result, producers
would be motivated to demonstrate that their feedstocks meet the
renewable biomass definition. However, this approach could also
increase compliance costs for obligated parties. For further discussion
of this approach, see Section III.H.4.
c. Review of Existing Programs
i. USDA Programs
To inform our approach for designing an implementation scheme for
the renewable biomass land restrictions under RFS2, we reviewed a
number of programs and models that track, certify, or verify
agricultural and silvicultural products or land use in the U.S. and
abroad. First we looked at several existing programs administered by
USDA that involve data collection from agricultural land owners,
farmers, and forest owners. However, while USDA obtains and maintains
valuable data from agricultural land owners, producers, and forest
owners for assessing the status of agricultural land, forest land, and
other types of land that could be used for renewable fuel feedstock
production, Section 1619 of the Food, Conservation, and Energy Act of
2008 (the 2008 Farm Bill) and policies of certain USDA agencies
significantly limit EPA's ability to access such data in a timely and
meaningful way. Given that agricultural land owners, producers, and
forest owners already report a great deal of information to USDA,
having access to such information could enable EPA to avoid having to
require duplicative reporting or recordkeeping and thereby minimize any
burden that RFS2 may place on parties in the renewable fuel feedstock
supply chain, from feedstock producer to renewable fuel producer, while
still allowing us to ensure that the land restrictions on renewable
biomass production are adhered to. We request comment on how EPA could
acquire the type of information submitted by parties such as
agricultural land owners, producers, and forest owners to USDA agencies
in order to aid in administering RFS2. Having access to such
information could be valuable to EPA in informing our enforcement
actions.
ii. Third-Party Programs
To inform our options for how we might verify and track renewable
biomass, we also explored non-governmental, third-party verification
programs used for certifying and tracking agricultural and forest
products from point of origin to point of use both within the U.S. and
outside the U.S. The United Kingdom and the EU are looking to such
third-party verification programs to implement the sustainability
provisions of their biofuels programs. There is no third-party
organization that certifies agricultural land, managed tree
plantations, and forests; rather, each generally focuses on one area.
Due to this constraint, we examined third party organizations that
certify specific types of biomass from croplands and organizations that
certify forest lands.
We examined third-party organizations that focus on a particular
type of feedstock used for renewable fuel production, including the
Roundtable on Sustainable Palm Oil and the Basel Criteria for
Responsible Soy Production. These initiatives have outlined traceable
certification programs for industry to follow. Two other cooperative
organizations whose primary concern is renewable fuel production from
biomass are the Roundtable on Sustainable Biofuels (RSB) and the Better
Sugarcane Initiative (BSI). At present, the RSB and BSI are still in
their developmental stages and do not have fully developed
certification processes.
We also examined the work of the international Soy Working Group,
comprised of representatives from industry, the Brazilian government,
and international non-governmental organizations (NGOs), which recently
announced a one-year extension of a moratorium on the use of soy
harvested from recently deforested lands in the Brazilian Amazon. This
moratorium is the result of a negotiated voluntary agreement through
which companies that purchase Brazilian soy work with their suppliers
to ensure that they source their soy from farms cultivated prior to
August 2006. The Brazilian Association of Vegetable Oil Industries
(ABIOVE) and Brazil's National Association of Grain Exporters (ANEC)
have used aerial photography to identify whether any newly deforested
areas were used to grow soy, and Greenpeace, one of the NGOs involved
in the agreement, uses satellite imagery and aerial photography to
perform spot checks for enforcement purposes.
Another new example of a renewable fuel feedstock verification
system is the
[[Page 24938]]
Verified Sustainable Ethanol initiative, which established a series of
criteria for ethanol produced in Brazil and sold to Swedish ethanol
importer SEKAB. The Brazilian sugarcane ethanol industry trade
association, UNICA, its member companies, and SEKAB established the
criteria to promote environmental and social sustainability of
sugarcane ethanol exported to Sweden. The agreement is between
companies, and it relies on a third-party auditor to inspect Brazilian
feedstock and ethanol production facilities to verify compliance with
the criteria.
We also examined third-party organizations that specialize in
certifying sustainable forest lands. The Sustainable Agriculture
Network (SAN), through the Rainforest Alliance, provides comprehensive
certification of wooded areas used for commercial development through
sustainable processes in the United States and Latin American
countries. The SAN certifies approximately 10 million acres of land
worldwide, with minimal agricultural land certified in the U.S.\22\
---------------------------------------------------------------------------
\22\ Forest acreage taken from USDA Economic Research Service,
Major uses of Land in the United States, 2002, Economic Information
Bulletin No. (EIB-14), May 2006.
---------------------------------------------------------------------------
We examined the certification process of the Forest Stewardship
Council (FSC) because of their international recognition for certifying
sustainable forests and their recordkeeping requirement for ``chain of
supply'' certification for products. The FSC certifies 22 million acres
of land in the U.S. according to certification standards designed for
nine separate regions within the U.S., and it provides an example for
chain-of-custody and product segregation requirements.\23\ Finally, we
examined the American Tree Farm program and Sustainable Forestry
Initiative (SFI).
---------------------------------------------------------------------------
\23\ FSC certified acreage taken from FSC-US, Prospectus, 2005.
---------------------------------------------------------------------------
The criteria used to certify participants through third-party
verification systems are overall more comprehensive and generally more
stringent than the land restrictions contained within the definition of
renewable biomass. However, three issues emerged through our
investigation of these existing third-party verification systems that
would make it difficult to adopt or incorporate any one of them into
our regulations for the land restriction provisions under EISA. First,
as previously noted, many of these third-party certifiers are limited
in the scope of products that they certify. Second, the acreage of
agricultural land or actively managed tree plantations certified
through third parties in the U.S. covers only a small portion of the
total available land and forests estimated to qualify for renewable
biomass production under the EISA definition. Third, none of the
existing third-party systems had definitions or criteria that perfectly
matched the land use definitions and restrictions contained in the EISA
definition of renewable biomass. Thus, we have determined that at this
time we cannot rely on any existing third-party verification program
solely to implement the land restrictions on renewable biomass under
RFS2. We believe there is potential benefit in utilizing third-party
verification programs if these issues can be addressed, and in the
following section we offer one possible scenario as an implementation
alternative. Nonetheless, we seek comment on our conclusion that there
are currently no appropriate third-party verification systems for
renewable biomass that could be adopted under RFS2. We further seek
comment on whether any existing program or combination of programs
would be able to meet the definitions and adopt the land restriction
criteria proposed for RFS2 to assist industry in meeting their
obligations under this proposed program.
d. Approaches for Domestic Renewable Fuel
Consistent with RFS1, renewable fuel producers would be responsible
for generating RINs under RFS2. In order to make a determination
whether or not their fuel is eligible for RINs, renewable fuel
producers would need to have at least basic information about the
origin of their feedstock. The following approaches for implementing
the land restrictions on renewable biomass contained in EISA illustrate
the variety of ways that renewable fuel feedstocks could be handled
under RFS2. These options are presented singly, but we seek comment on
how they might be combined to create the most appropriate, practical,
and enforceable implementation scheme for renewable biomass under RFS2.
One approach for ensuring that producers generate RINs properly
would be for EPA to require that renewable fuel producers obtain
documentation about their feedstocks from their feedstock supplier(s)
and take the measures necessary to ensure that they know the source of
their feedstocks and can demonstrate to EPA that they have complied
with the EISA definition of renewable biomass. Under this approach, EPA
would require renewable fuel producers who generate RINs to certify on
their renewable fuel production reports that the feedstock used for
each renewable fuel batch meets the definition of renewable biomass. We
would require renewable fuel producers to maintain sufficient records
to support these claims. Specifically, renewable fuel producers who use
planted crops or crop residue from existing agricultural land, or who
use planted trees or slash from actively managed tree plantations,
would be required to have copies of their feedstock producers' written
records that serve as evidence of land being actively managed (or
fallow, in the case of agricultural land) since December 2007, such as
sales records for planted crops or trees, livestock, crop residue, or
slash; a written management plan for agricultural or silvicultural
purposes; or, documentation of participation in an agricultural or
silvicultural program sponsored by a Federal, state or local government
agency. In the case of all other biomass, we would require renewable
fuel producers to have, at a minimum, written certification from their
feedstock supplier that the feedstock qualifies as renewable biomass.
We seek comment on whether we should also require renewable fuel
producers that use slash and pre-commercial thinnings from non-federal
forestland and biomass from areas at risk of wildfire to maintain
additional records to support the claim that these feedstocks meet the
definition of renewable biomass. These records could include sworn
statements from licensed or registered foresters, contracts for tree or
slash removal or documentation of participation in a fire mitigation
program. We seek comment on other methods of verifying renewable fuel
producers' claims that feedstocks qualify for these categories of
renewable biomass. A review of such records would become part of the
producer's annual attest engagement, the annual audit of their records
by an independent third party (see Section IV.A for a full discussion
of attest engagement requirements).
A renewable fuel producer would only be permitted to produce and
sell renewable fuel without RINs if he demonstrates that the feedstocks
used to produce his fuel do not meet the definition of renewable
biomass. This approach would ensure that renewable fuel producers could
not avoid the generation of RINs simply by failing to make a
demonstration regarding the land used to produce their feedstocks.
Thus, renewable fuel producers would be required to keep records of
their feedstock source(s), regardless of
[[Page 24939]]
whether RINs were generated or not. At a minimum, renewable fuel
producers who do not generate RINs would need to have certification
from their feedstock supplier that their feedstock does not meet the
definition of renewable biomass. In the event that some portion of a
load of feedstock does meet the definition of renewable biomass and
some portion does not, the renewable fuel producer would need to
maintain documentation from their supplier that states the percentage
of each portion. All of these records would be included as part of the
renewable fuel producer's annual attest engagement. The renewable fuel
producer would also indicate on his renewable fuel production report
that he did not generate RINs for fuel made from feedstock that did not
meet the definition of renewable biomass.
Some stakeholders have expressed concern about EPA specifying the
records that a renewable fuel producer must obtain from their feedstock
supplier. We therefore seek comment on an approach that would require
renewable fuel producers to certify on their renewable fuel production
reports that their feedstock either met or did not meet the definition
of renewable biomass and would require producers to maintain sufficient
records to support their claims, but would stop short of specifying
what those records would have to include. We anticipate that a large
portion of feedstocks that qualify as renewable biomass will be
obtained from existing agricultural land or actively managed tree
plantations, for which, by definition, documentation already exists. We
believe that, in most other cases, feedstock producers will have or
will be able to create other forms of documentation that could be
provided to renewable fuel producers in order to provide adequate
assurance that the feedstock in question meets the definition of
renewable biomass. As described above, there are many existing
programs, such as those administered by USDA and independent third-
party certifiers, that could be useful to verify that feedstock from
certain land qualifies as renewable biomass.
We anticipate that these self-certification approaches would result
in renewable fuel producers amending their contracts and altering their
supply chain interactions to satisfy their need for documented
assurance and proof about their feedstock's origins. Enforcement under
either of these approaches would rely in part on EPA's review of
renewable fuel production reports and attest engagements of renewable
fuel producers' records. EPA would also consult other data sources,
including any data made available by USDA, and could conduct site
visits or inspections of feedstock producers' and suppliers'
facilities. We seek comment on the feasibility and practical
limitations of EPA working with publicly available USDA data to keep
track of significant land use changes in the U.S. and around the world
and to note general increases in feedstock supplier productivity that
might signal cultivation of new agricultural land for renewable fuel
feedstock production.
Either of these approaches would easily fold into existing and
newly proposed registration, recordkeeping, reporting, and attest
engagement procedures. They would also place the burden of
implementation and enforcement on renewable fuel producers rather than
bringing feedstock producers and suppliers directly under EPA
regulation. In this way, they would minimize the number of regulated
parties under RFS2. They would also allow, to varying degree, the
renewable fuel industry to determine the most efficient means of
verifying and tracking feedstocks from the point of production to the
point of consumption, thereby minimizing any additional cost and
administrative burden created by the EISA definition of renewable
biomass.
Another alternative would be for EPA to establish a chain-of-
custody tracking system from feedstock producer to renewable fuel
producer through which renewable fuel producers would obtain
information regarding the lands where their feedstocks were produced.
This information would accompany each transfer of custody of the
feedstock until the feedstock reaches the renewable fuel producer.
Renewable fuel feedstock producers, suppliers and handlers would not
have any reporting obligations. EPA would, however, require all
feedstock producers, suppliers, and handlers to maintain as records
these chain-of-custody documents for all biomass intended to be used as
a renewable fuel feedstock. Renewable fuel producers would also be
required to maintain these chain-of-custody tracking documents in their
records and would have to include them as part of their records
presented during their annual attest engagement.
An additional alternative would be for EPA to require renewable
fuel producers to set up and administer a quality assurance program
that would create an additional level of rigor in the implementation
scheme for the EISA land restrictions on renewable biomass. The quality
assurance program could include (1) an unannounced independent third
party inspection of the renewable feedstock producer's facility at
least once per quarter or once every 15 deliveries, whichever is more
frequent, (2) an unannounced independent third party inspection of each
intermediary facility that stores renewable fuel feedstock received by
the renewable fuel producer at least once per quarter, and (3) on each
occasion when the independent third party inspection reveals
noncompliance, the renewable fuel producer must (a) conduct an
investigation to determine the proper number of RINs that should have
been generated for a volume of fuel and either generate or retire an
equal number of RINs, depending on whether the fuel's feedstock did or
did not meet the definition of renewable biomass, (b) conduct a root
cause analysis of the violation, and (c) refuse to accept or process
feedstock from the renewable fuel feedstock producer unless or until
the feedstock producer takes appropriate corrective action to prevent
future violations.
This alternative could provide a partial affirmative defense either
for renewable producers that illegally generate RINs for fuel made from
feedstocks that do not qualify as renewable biomass or for renewable
fuel producers who do not generate enough RINs for fuel made from
feedstocks that do qualify as renewable biomass. In either case, the
producers must demonstrate that the violation was caused by a feedstock
producer or supplier and not themselves; that the commercial documents
(e.g., bills of lading) received with the feedstock indicated that the
feedstock either met (in the case that RINs were generated illegally)
or did not meet (in the case that an inadequate number of RINs were
generated) the land restrictions for renewable biomass, and that they
met EPA's quality assurance program requirements. A renewable fuel
producer that generates RINs for fuel made from a feedstock that does
not meet the definition of renewable biomass, but that qualifies for
the partial affirmative defense, would still have to retire a number of
RINs equal to the illegally generated RINs. Likewise, a renewable fuel
producer that does not generate sufficient RINs for fuel made from a
feedstock that does meet the definition of renewable biomass, but that
qualifies for the partial affirmative defense, would have to generate
enough RINs to make up the difference. However, in neither case would
they be subject to civil penalties.
As yet another alternative approach, EPA could bring together
renewable fuel producers and renewable fuel feedstock producers and
suppliers to develop an industry-wide quality assurance
[[Page 24940]]
program for the renewable fuel production supply chain, following the
model of the successful Reformulated Gasoline Survey Association. We
believe that this alternative could be less costly than if each
individual renewable fuel producer were to create their own quality
assurance program, and it would add a quality assurance element to RFS2
while creating the possibility for a partial affirmative defense for
renewable fuel producers and feedstock producers and suppliers.
The program would be carried out by an independent surveyor funded
by industry and consist of a nationwide verification program for
renewable fuel producers and renewable feedstock producers and handlers
designed to provide independent oversight of the feedstock designations
and handling processes that are required to determine if a feedstock
meets the definition of renewable biomass. Under this alternative, a
renewable fuel producer and its renewable feedstock suppliers and
handlers would have to participate in the funding of an organization
which arranges to have an independent surveyor conduct a program of
compliance surveys. Compliance surveys would be carried out by an
independent surveyor pursuant to a detailed survey plan submitted to
EPA for approval by November 1 of the year preceding the year in which
the alternative quality assurance sampling and testing program would be
implemented. The survey plan would include a methodology for
determining when the survey samples would be collected, the locations
of the surveys, the number of inspections to be included in the survey,
and any other elements that EPA determines are necessary to achieve the
same level of quality assurance as the requirement included in the RFS2
regulations at the time.
Under this alternative, the independent surveyor would be required
to visit renewable feedstock producers and suppliers to determine if
they are properly designating their product and adhering to adequate
chain of custody requirements. This nationwide sampling program would
be designed to ensure even coverage of renewable feedstock producers
and suppliers. The surveyor would generate and report the results of
the surveys to EPA each calendar quarter. In addition, where the survey
finds improper designations or handling, the liable parties would be
responsible for identifying and addressing the root cause of the
violation to prevent future violations. When a violation is detected,
the renewable fuel producer that participates in the consortium would
be deemed to have met the quality assurance criteria for a partial
affirmative defense. If the renewable fuel producer met the other
applicable criteria, he would have to take corrective action to retire
or generate the appropriate number of RINs depending on the violation,
but he would not be subject to civil penalties.
Some stakeholders have suggested that EPA take advantage of
existing satellite and aerial imagery and mapping software and tools to
implement the renewable biomass provisions of EISA. One way to do so
would be for EPA to develop a renewable fuel mapping Web site to assist
regulated parties in meeting their obligation to identify the location
of land where renewable fuel feedstocks are produced. Such a Web site
could include an interactive map that would allow renewable feedstock
producers to trace the boundaries of their property and create an
electronic file with information regarding the land where their
renewable fuel feedstocks were produced, such as a code that identifies
the plot of land. This would allow the feedstock producer to provide
information, such as a standard land ID code, on all bills of lading or
other commercial documents that identify the type and quantity of
feedstock being delivered to the renewable fuel producer. Renewable
fuel producers could then make a determination regarding whether or not
the renewable fuel feedstock that they use meets the definition of
renewable biomass, and is therefore eligible or not for RIN generation.
Feedstock producers would not necessarily be required to use this
Internet-based tool to identify the location where renewable fuel
feedstocks are produced, since many feedstock producers already
participate in various government or insurance programs that have
required them to map the location of their fields. But the map would
enable renewable fuel producers to verify the accuracy of these
descriptions and report these locations to EPA using the interactive
mapping tool on EPA's Web site. EPA specifically solicits comment on
the practicability of constructing an accurate map from existing data
sources.
As noted above, EPA recognizes that land restrictions contained
within the definition of renewable biomass may not, in practice, result
in a significant change in agricultural practices. EPA also recognizes
that the implementation options described in this proposal could impose
costs and constraints on existing storage, transportation, and delivery
systems for feedstocks, in particular for corn and soybeans in the U.S.
We therefore seek comment on a stakeholder suggestion to establish a
baseline level of production of biomass feedstocks such that reporting
and recordkeeping requirements would be triggered only when the
baseline production levels of feedstocks used for biofuels were
exceeded. Such an approach would avoid imposing a new recordkeeping
burden on the industry as long as biofuels demand is met with existing
feedstock production. We seek comment on this alternative, including
how to set the baseline production levels and information on
appropriate data sources in the U.S. and in other countries that
produce feedstocks that could be used for renewable fuel production,
and on how to track whether the feedstock use for biofuels production
has exceeded baseline production levels. We also solicit comment on
whether this approach could be applied to all types of feedstocks on
which EISA places land restrictions, or if it would only be appropriate
for traditional agricultural crops such as corn, soybeans, and
sugarcane for which historical acreage data exists both domestically
and internationally.
EPA acknowledges that under this alternative, while there could be
a net increase in lands being cultivated for a particular crop, we
would presume that increases in cultivation would be used to meet non-
biofuels related feedstock demand. We also acknowledge that such an
approach would be difficult to enforce because data that could indicate
that baseline production levels were exceeded in a given year would
likely be delayed by many months, such that the recordkeeping
requirements for renewable fuel producers would also be delayed. During
the interim period, renewable fuel producers would have generated RINs
for fuel that did not qualify for credit under the program, and any
remedial steps to invalidate such RINs after the fact could be costly
and burdensome to all parties in the supply chain. Nonetheless, we seek
comment on the approach as described above.
We seek comment on all of these approaches and what combination of
these approaches would be the most appropriate, enforceable, and
practical for ensuring that the land restrictions on renewable biomass
contained in EISA are implemented under RFS2. We also seek comment on
whether there are other possible approaches that would be superior to
those we have described above. We also note that we intend to monitor
RIN generation and the trends
[[Page 24941]]
in renewable fuel feedstock sources as RFS2 implementation gets
underway, and that we may make changes to the approach we adopt in the
final RFS2 regulations if renewable fuel feedstock production
conditions change or if new, better renewable biomass verification
tools become available.
e. Approaches for Foreign Renewable Fuel
EISA creates unique challenges related to the implementation and
enforcement of the definition of renewable biomass for foreign-produced
renewable fuel. In order to address these issues, we propose to require
foreign producers of renewable fuel who export to the U.S. to meet the
same compliance obligations as domestic renewable fuel producers. These
obligations would include facility registration and submittal of
independent engineering reviews (described in Section III.C below), and
reporting, recordkeeping, and attest engagement requirements. They
would also include the same obligations that domestic producers have
for verifying that their feedstock meets the definition of renewable
biomass as described above, such as certifying on each renewable fuel
production report that their renewable fuel feedstock meets the
definition of renewable biomass and working with their feedstock
supplier(s) to ensure that they receive and maintain accurate and
sufficient documentation in their records to support their claims. As
under the RFS1 program for producers of cellulosic fuel, the foreign
producer would be required to comply with additional requirements
designed to ensure that enforcement of the regulations at the foreign
production facility would not be compromised. For instance, foreign
producers would be required to designate renewable fuel intended for
export to the U.S. as such and segregate the volume until it reaches
the U.S. and post a bond to ensure that penalties can be assessed in
the event of a violation. Moreover, as a regulated party under the RFS2
program, foreign producers would have to allow for potential visits by
EPA enforcement personnel to review the completeness and accuracy of
records and registration information.
We propose that a foreign renewable fuel producer, like a domestic
renewable fuel producer, could only produce and sell renewable fuel for
export to the U.S. without RINs if he demonstrated that the land used
to produce his feedstocks did not meet the definition of renewable
biomass. This approach would ensure that foreign renewable fuel
producers could not avoid the generation of RINs for fuel shipped to
the U.S. simply by failing to make any demonstration regarding the land
used to produce their feedstocks. Thus, foreign renewable fuel
producers that export their product to the U.S. would be required to
keep records of the type of land used to produce their feedstock
regardless of whether RINs are generated or not. Section III.D.2.b
outlines more specifically our proposed requirements for foreign
renewable fuel producers.
Importers will likely have less knowledge than a foreign renewable
fuel producer would about the point of origin of their fuel's feedstock
and whether it meets the definition of renewable biomass. Therefore, we
are proposing that in the event that a batch of foreign-produced
renewable fuel does not have RINs accompanying it, an importer must
obtain documentation from its producer that states whether or not the
definition of renewable biomass was met by the fuel's feedstock. With
such documentation, the importer would be required to generate RINs (if
the definition of renewable biomass is met) or would be prohibited from
doing so (if the definition is not met) prior to introducing the fuel
into commerce in the U.S. Without such documentation, the fuel would
not be permitted for importation. Section III.D.2.c outlines our
proposed requirements for importers more fully.
We seek comment on whether and to what extent the approaches for
ensuring compliance with the EISA's land restrictions by foreign
renewable fuel producers could or should differ from the proposed
approach for domestic renewable fuel producers. In light of the
challenges associated with enforcing the EISA's land restrictions in
foreign countries, we believe that it may be appropriate to require
foreign renewable fuel producers to use an alternative method of
demonstrating compliance with these requirements. We seek comment on
whether foreign renewable producers exporting product to the U.S.
should have to comply with any of the alternatives described for
domestic renewable fuel producers under this section. For example, we
seek comment on whether a foreign renewable fuel producer should have
to demonstrate that it had a contract in place with its renewable
feedstock producer that required designation and chain of custody and
handling methods similar to one of the alternatives for domestic
renewable fuel producers discussed above. We also seek comment on
whether foreign renewable fuel producers that export product to the
U.S. should have to provide EPA with the location of land from which
they will or have acquired feedstocks, along with historical satellite
or aerial imagery demonstrating that feedstocks from these lands meet
the definition of renewable biomass. We seek comment on whether foreign
renewable fuel producers should also be subject to the same quality
assurance requirements relating to their feedstock sources as domestic
renewable fuel producers, and whether they should have the same option
to use an approved survey consortium in lieu of implementing their own
individual quality assurance programs.
We also seek comment on an alternative that would provide foreign
renewable fuel producers an option of participating in RFS2 (in a
manner consistent with our main proposal), or not participating at all.
If they elected not to participate in RFS2, they could export renewable
fuel to the United States without RINs, and without providing any
documentation as to whether or not the fuel was made with renewable
biomass. However, they would also have to meet requirements for
segregating their fuel from renewable fuel for which RINs were
generated, and the importer of their fuel would be required to track it
to ensure that the fuel remains segregated in the U.S. and is not used
by a domestic company for illegal RIN generation. This alternative
would provide foreign renewable fuel producers an option not available
to domestic renewable fuel producers, who in all cases would be
required to document whether or not their feedstock met the definition
of renewable biomass, and who would be required to generate RINs for
their product if it was. As discussed in Section III.B.4.b.ii of this
preamble, EPA believes that in order for obligated parties to meet the
increasing annual volume requirements under RFS2, all qualifying
renewable fuel will need to have RINs generated for it. Nonetheless,
this alternative recognizes the potential difficulty of applying
renewable biomass verification procedures in the international context,
and provides an exemption process that EPA expects would only be used
by relatively small producers for whom the burden of participating in
the RFS2 program would outweigh the benefits, and whose total
production volume would be negligible.
C. Expanded Registration Process for Producers and Importers
In order to implement and enforce the new restrictions on
qualifying renewable fuel under RFS2, we are proposing that the
registration process
[[Page 24942]]
for renewable fuel producers and importers be revised. Under the
existing RFS1 program, all producers and importers of renewable fuel
who produce or import more than 10,000 gallons of fuel annually must
register with EPA's fuels program prior to generating RINs. Renewable
fuel producer and importer registration under the existing RFS program
consists of filling out two forms: 3520-20A (Fuels Programs Company/
Entity Registration), which requires basic contact information for the
company and basic business activity information (e.g., for an ethanol
producer, they need to indicate that they are a RIN generator), and
3520-20B (Gasoline Programs Facility Registration) or 3520-20B1 (Diesel
Programs Facility Registration), which requires basic contact
information for each facility owned by the producer or importer. More
detailed information on the renewable fuel production facility, such as
production capacity and process, feedstocks, and products is not
required for most producers or importers to generate RINs under RFS1
(producers of cellulosic biomass ethanol and waste-derived ethanol are
the exception to this).
Due to the revised definitions of renewable fuel under EISA, as
well as other changes, we believe it necessary to expand the
registration process for renewable fuel producers and importers in
order to implement the new program effectively. Specifically,
generating and assigning a certain category of RIN to a volume of fuel
is dependent on whether the feedstock used to produce the fuel meets
the definition of renewable biomass, whether the lifecycle greenhouse
gas emissions of the fuel meets a certain GHG reduction threshold and,
in some cases, whether the renewable fuel production facility is
considered to be grandfathered into the program. Unless we require
producers, including foreign producers, and importers to provide us
with information on their feedstocks, facilities, and products, we
cannot adequately implement or enforce the program or have confidence
that producers and importers are properly categorizing their fuel and
generating RINs. In particular, our proposed approach for ensuring that
the GHG emission reduction thresholds for each category of renewable
fuel are met will require producers and importers to determine the
proper category assignment for their fuel based on a combination of
their feedstock, production processes, and products (see Section
III.D.2 for the proposed list). Such information, therefore, is central
to program implementation. Therefore, we are proposing new registration
requirements for all domestic renewable fuel producers, importers, and
foreign renewable fuel producers. We also plan on integrating
registration procedures with the new EPA Moderated Transaction System,
discussed in detail in Section IV.E of this preamble. We encourage
those affected by the proposed registration requirements to review the
document entitled ``Proposed Information Collection Request (ICR) for
the Renewable Fuels Standard (RFS2) Program--EPA ICR 2333.01,'' and an
Addendum to the proposed ICR, which have been placed in the public
docket and to provide comments to us regarding the burdens associated
with the proposed registration requirements.
1. Domestic Renewable Fuel Producers
The most significant proposed changes to the current registration
system pertain to the information that a producer will need to provide
EPA prior to generating RINs. As noted above, we are proposing that
producers provide information about their products, feedstocks, and
facilities in order to be registered for the RFS2 program. Information
contained in a producer's registration would be used to verify the
validity of RINs generated and their proper categorization as either
cellulosic biofuel, biomass-based diesel, advanced biofuel, or other
renewable fuel.
With respect to products, we are interested in the types of
renewable fuel and co-products that a facility is capable of producing.
With respect to feedstocks, we believe it is necessary to have on file
a list of all the different feedstocks that a renewable fuel producer's
facility is capable of converting into renewable fuel. For example, if
a renewable fuel producer produces fuel from both cellulosic material,
such as corn stover, and non-cellulosic material, such as corn starch,
the producer may be eligible to generate RINs in two different
categories (cellulosic biofuel and renewable fuel). This producer's
registration information would be required to list both of these
feedstocks before we would allow two different categories of RINs to be
generated.
With respect to the producer's facilities, we are proposing two
types of information that would need to be reported to the Agency.
First, we believe it is important to have information on file that
describes each facility's fuel production processes (e.g., wet mill,
dry mill, thermochemical, etc.), and thermal/process energy source(s).
Second, in order to determine what production volumes would be
grandfathered and thus deemed to be in compliance with the 20% GHG
threshold, we would require evidence and certification of the
facility's qualification under the definition of ``commence
construction'' as well as information necessary to establish it's
renewable fuel baseline volume per the proposal outlined in Section
III.B.3 of this preamble.
Under the existing RFS1 program, producers of cellulosic biomass
and waste-derived ethanol are required to have an annual engineering
review of their production records performed by an independent third
party who is licensed Professional Engineer (P.E.) who works in the
chemical engineering field. This independent third party need not be
based in the United States, but must hold a P.E. Each review must be
kept on file by both the producer and the engineer for five years. The
independent third party must include documentation of its
qualifications as part of the engineering review. Foreign producers of
cellulosic biomass and waste-derived ethanol are also required to have
an engineering review of their facilities, with a report submitted to
EPA that describes in detail the physical plant and its operation.
These requirements helps ensure that producers who claim to be
producing such fuel, which earns 2.5 RINs per gallon rather than 1.0
RIN per gallon for corn-based ethanol under RFS1, are in fact doing so.
We believe that the requirement for an on-site engineering review
is an effective implementation tool and propose to adopt the
requirement under RFS2, with the following changes. First, we propose
expanding the applicability of the requirement to all renewable fuel
producers due to the variability of production facilities, the increase
in the number of categories of renewable fuels, and the importance of
generating RINs in the correct category. Second, we propose that every
renewable fuel producer must have the on-site engineering review of
their facility performed in conjunction with his or her initial
registration for the new RFS program in order to establish the proper
basis for RIN generation, and every three years thereafter to verify
that the fuel pathways established in their initial registration are
still applicable. These requirements would apply unless the renewable
fuel producer updates its facility registration information to qualify
for a new RIN category (i.e., D code), in which case the review would
need to be performed within 60 days of the registration update.
Finally, we propose that producers be required to
[[Page 24943]]
submit a copy of their independent engineering review to EPA rather
than simply maintaining it in their records. We believe that this extra
step is necessary for verification and enforcement purposes.
In addition to the new registration requirements for all renewable
fuel producers who produce greater than 10,000 gallons of product each
year, we seek comment on whether to require renewable fuel producers
and importers in the U.S. who produce or import less than 10,000
gallons per year to register basic information about their company and
facility (or facilities) with EPA, similar to information currently
required of renewable fuel producers under RFS1. This information would
complement information submitted to EPA under the Fuels and Fuel
Additives Registration System (FFARS) program to help ensure that EPA
has a complete record of renewable fuel production and importation in
the U.S.
2. Foreign Renewable Fuel Producers
Under the current RFS program, foreign renewable fuel producers of
cellulosic biomass ethanol and waste-derived ethanol may apply to EPA
to generate RINs for their own fuel. This allows a foreign producer of
this renewable fuel to obtain the same benefits of higher credit value
as domestic producers of this category of renewable fuel. Under the
RFS1 regulations, the foreign fuel producer must meet a variety of
requirements established to make the program effective and enforceable
with respect to a foreign producer. These requirements mirror a number
of similar fuel provisions that apply to foreign refiners in other
fuels programs. For RFS2, we propose that foreign producers of
renewable fuel must meet the same requirements as domestic producers,
including registering information about their feedstocks, facilities,
and products, as well as submitting an on-site independent engineering
review of their facilities at the time of registration for the program
and every three years thereafter. These requirements would apply to all
foreign renewable fuel producers who export their products to the U.S.,
whether or not they qualify to generate RINs for their fuel. They would
also be subject to the variety of enforcement related provisions that
apply under RFS1 to foreign producers of cellulosic biomass or waste
derived ethanol.
As discussed in Section III.C.1, the existing RFS1 program requires
that the independent engineering review be conducted by an independent
third party who is a licensed P.E. who works in the chemical
engineering field. This P.E. need not be based in the United States.
The independent third party must include documentation of its
qualifications as part of the engineering review.
Since implementation of RFS1 we have received questions about
engineers who are licensed by other countries that may have equivalent
licensing requirements to those associated with the P.E. designation in
the United States. The existing RFS1 program does not permit
independent third party review by a party who is not a licensed P.E. We
invite comment on whether or not we should permit independent third
parties who are based in--and licensed by--foreign countries and who
work in the chemical engineering field to demonstrate the foreign
equivalency of a P.E. license.
We also seek comment on requiring foreign renewable fuel producers
to provide EPA with the location of land from which they will acquire
feedstocks, along with historical satellite or aerial imagery
demonstrating that the lands from which they acquire feedstock are
eligible under the definition of renewable biomass (see Section III.B.4
for a full discussion of our proposed and alternative approaches for
foreign renewable fuel producers to verify their feedstocks meet the
definition of ``renewable biomass'').
3. Renewable Fuel Importers
A renewable fuel importer is required under RFS1 to register basic
information about their company with EPA prior to generating RINs.
Under the proposed new RFS2 program, we are proposing that only in
limited cases can importers generate RINs for imported fuel that they
receive without RINs. In any case, whether they receive fuel with or
without RINs, an importer must rely on his supplier, a foreign
renewable fuel producer, to provide documentation to support any claims
for their decision to generate or not to generate RINs. An importer may
have an agreement with a foreign renewable fuel producer for the
importer to generate RINs if the foreign producer has not done so
already. However, the foreign renewable fuel producer must be
registered with EPA as noted above. Section III.D.2.c describes our
proposed RIN generating restrictions and requirements for importers
under RFS2.
4. Process and Timing
We intend to make forms for expanded registration for renewable
fuel producers and importers available electronically, with paper
registration only in exceptional cases. We propose that registration
forms will have to be submitted by January 1, 2010 (the proposed
effective date of the final RFS2 regulations), or 60 days prior to a
producer producing or importer importing any renewable fuel, whichever
dates comes later. If a producer changes to a feedstock that is not
listed in his registration information on file with EPA but the
feedstock will not incur a change of RIN category for the fuel (i.e., a
change in the appropriate D code), then we propose that the producer
must update his registration information within seven (7) days of the
change. However, if a producer's feedstock, facility (including
industrial processes or thermal energy source), or products undergo
changes that would qualify his renewable fuel for a new RIN category
(and thus a new D code), then we propose that such an update would need
to be submitted at least 60 days prior to the change, followed by
submittal of a complete on-site independent engineering review of the
producer's facility also within 60 days of the change.
D. Generation of RINs
Under RFS2, each RIN would continue to be generated by the producer
or importer of the renewable fuel, as in the RFS1 program. In order to
determine the number of RINs that must be generated and assigned to a
batch of renewable fuel, the actual volume of the batch of renewable
fuel must be multiplied by the appropriate Equivalence Value. The
producer or importer must also determine the appropriate D code to
assign to the RIN to identify which of the four standards the RIN can
be used to meet. This section describes these two aspects of the
generation of RINs. We propose that other aspects of the generation of
RINs, such as the definition of a batch and temperature
standardization, as well as the assignment of RINs to batches, should
remain unchanged from the RFS1 requirements.
1. Equivalence Values
For RFS1, we interpreted CAA section 211(o) as allowing us to
develop Equivalence Values representing the number of gallons that can
be claimed for compliance purposes for every physical gallon of
renewable fuel. We described how the use of Equivalence Values adjusted
for renewable content and based on energy content in comparison to the
energy content of ethanol was consistent with Congressional intent to
treat different renewable fuels differently in different circumstances,
and to provide
[[Page 24944]]
incentives for use of renewable fuels in certain circumstances, as
evidenced by the specific circumstances addressed by Congress. This
included the direction that EPA establish ``appropriate'' credit values
in certain circumstances, as well as provisions in the statute
providing for different credit values to be assigned to the same volume
of different types of renewable fuels (e.g., cellulosic and waste-
derived fuels). We also noted that the use of Equivalence Values based
on energy content was an appropriate measure of the extent to which a
renewable fuel would replace or reduce the quantity of petroleum or
other fossil fuel present in a fuel mixture. The result was an
Equivalence Value for ethanol of 1.0, for butanol of 1.3, for biodiesel
(mono alkyl ester) of 1.5, and for non-ester renewable diesel of 1.7.
EPA stated that these provisions indicated that Congress did not intend
to limit the RFS program solely to a straight volume measurement of
gallons. EPA also noted that the use of Equivalence Values would not
interfere with meeting the overall volume goals specified by Congress,
given the various provisions that make achievement of the specified
volumes imprecise. See 72 FR 23918-23920, and 71 FR 55570-55571.
EISA has not changed certain of the statutory provisions we looked
to for support under RFS1 in establishing Equivalence Values based on
relative volumetric energy content in comparison to ethanol. For
instance, CAA 211(o) continues to give EPA the authority to determine
an ``appropriate'' credit for biodiesel, and also directs EPA to
determine the ``appropriate'' amount of credit for renewable fuel use
in excess of the required volumes.
However, EISA made a number of other changes to CAA section 211(o)
that impact our consideration of Equivalence Values in the context of
the RFS2 program. For instance, EISA eliminated the 2.5-to-1 credit for
cellulosic biomass ethanol and waste-derived ethanol and replaced this
provision with large mandated volumes of cellulosic biofuel and
advanced biofuels. Under the RFS1 program, an Equivalence Value of 2.5
applies to these types of ethanol through the end of 2012. Under the
new RFS2 program, these types of ethanol would have an Equivalence
Value of 1.0, consistent with all other forms of ethanol.
EISA also expanded the program to include four separate categories
of renewable fuel (cellulosic biofuel, biomass-based diesel, advanced
biofuel, and total renewable fuel) and included GHG thresholds in the
definitions of each category. Each of these categories of renewable
fuel has its own volume requirement, and thus there will exist a
guaranteed market for each. As a result there may no longer be a need
for additional incentives for certain fuels in the form of Equivalence
Values greater than 1.0. In addition, the use of an energy-based
approach to Equivalence Values raises some questions, discussed below,
concerning the impact of such Equivalence Values on the biomass-based
diesel volume requirement and in the initial years on the advanced
biofuel volume requirement. Overall EPA believes that the statute
continues to be ambiguous on this issue, and we are therefore co-
proposing and seeking comment on two options for Equivalence Values:
1. Equivalence Values would be based on the energy content and
renewable content of each renewable fuel in comparison to denatured
ethanol, consistent with the approach under RFS1.
2. All liquid renewable fuels would be counted strictly on the
basis of their measured volumes, and the Equivalence Values for all
renewable fuels would be 1.0 (essentially, Equivalence Values would no
longer apply).
While these two different approaches to volume would have an impact
on the market values of renewable fuels with different energy contents
as explained more fully below, the overall impact on the program would
likely be small since we are projecting that the overwhelming majority
of renewable fuels will be ethanol (see further discussion in Section
V.A.2).
Under either option, non-liquid renewable fuels such as biogas and
renewable electricity would continue to be valued based on the energy
contained in one gallon of denatured ethanol. In the RFS1 final
rulemaking, we specified that 77,550 Btu of biogas be counted as the
equivalent of 1 gallon of renewable fuel with an assigned Equivalence
Value of 1.0. We propose to maintain this approach to non-liquid
renewable fuels under the RFS2 program under either approach to
Equivalence Values, but with a small modification to make the ethanol
energy content more accurate. The energy content of denatured ethanol
was specified as 77,550 Btu/gal under RFS1, but a more accurate value
would be 77,930 Btu/gal. Thus we propose to use 77,930 Btu to convert
biogas and renewable electricity into volumes of renewable fuel under
RFS2.
Under the second option in which all liquid renewable fuels would
be counted strictly on the basis of their measured volumes, we would
need to determine how to treat the small amount of denaturant in
ethanol and the nonrenewable portion of biodiesel. Under RFS1,
Equivalence Values were determined from a formula that included
measures of both volumetric energy content and renewable content. The
renewable content was intended to take into account the portion, if
any, of a renewable fuel that originated from a fossil fuel feedstock.
EISA eliminated the statutory language on which the inclusion of
renewable content was based, and instead restricts renewable fuels that
are valid under the RFS2 program to those produced from renewable
biomass. In the case of fuels produced from both renewable and
nonrenewable feedstocks, we have interpreted this to mean only that
portion of the volume attributable to the renewable feedstocks (see
further discussion in Section III.D.4 below). However, we do not
believe that this approach is appropriate for the denaturant in ethanol
and the small amount of non-renewable methanol used in the production
of biodiesel, since Congress clearly intended that ethanol and
biodiesel be included as a renewable fuel, and they are only used as a
fuel under these circumstances. We therefore propose to treat the
denaturant in ethanol and the nonrenewable portion of biodiesel as de
minimus and thus count them as part of the renewable fuel volume under
an approach to Equivalence Values in which all liquid renewable fuels
would be counted strictly on the basis of their measured volumes. As a
result, under this co-proposed approach we are proposing that the full
formula used to calculate Equivalence Values under RFS1 be eliminated
from the regulations and that the Equivalence Value for all renewable
fuels be specified as 1.0. Nevertheless, we seek comment on this
approach.
Although there are several reasons for a straight volume approach
as discussed above, there are also several reasons to maintain the
ethanol-equivalent energy content approach to Equivalence Values of
RFS1. For instance, in our discussions with stakeholders, some have
argued that the existence of four standards is not a sufficient reason
to eliminate the use of energy-based Equivalence Values for RFS2. The
four categories are defined in such a way that a variety of different
types of renewable fuel could qualify for each category, such that no
single specific type of renewable fuel will have a guaranteed market.
For example, the cellulosic biofuel requirement could be met with both
cellulosic ethanol or cellulosic diesel. As a result, the existence of
four standards under RFS2 may not obviate the value of standardizing
for energy
[[Page 24945]]
content, which provides a level playing field under RFS1 for various
types of renewable fuels based on energy content.
More importantly, they argue that a straight volume approach would
be likely to create a disincentive for the development of new renewable
fuels that have a higher energy content than ethanol in the same way as
the current ethanol tax credit structure. For a given mass of
feedstock, the volume of renewable fuel that can be produced is roughly
inversely proportional to its energy content. For instance, one ton of
biomass could be gasified and converted to syngas, which could then be
catalytically reformed into either 90 gallons of ethanol (and other
alcohols) or 50 gallons of diesel fuel (and naphtha).\24\ If RINs were
assigned on a straight volume basis, the producer could maximize the
number of RINs he is able to generate and sell by producing ethanol
instead of diesel. Thus, even if the market would otherwise lean
towards demanding greater volumes of diesel, the greater RIN value for
producing ethanol may favor its production instead. However, if the
energy-based Equivalence Values were maintained, the producer could
assign 1.7 RINs to each gallon of diesel made from biomass in
comparison to 1.0 RIN to each gallon of ethanol from biomass, and the
total number of RINs generated would be essentially the same for the
diesel as it would be for the ethanol. The use of energy-based
Equivalence Values could thus provide a level playing field in terms of
the RFS program's incentives to produce different types of renewable
fuel from the available feedstocks. The market would then be free to
choose the most appropriate renewable fuels without any bias imposed by
the RFS regulations, and the costs imposed on different types of
renewable fuel through the assignment of RINs would be more evenly
aligned with the ability of those fuels to power vehicles and engines,
and displace fossil fuel-based gasoline or diesel.
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\24\ Another example would be a fermentation process in which
one ton of cellulose could be used to produce either 70 gallons of
ethanol or 55 gallons of butanol.
---------------------------------------------------------------------------
Moreover, the technologies for producing more energy-dense fuels
such as cellulosic diesel are still in the early stages of development
and may benefit from not having to overcome the disincentive in the
form of the same Equivalence Value based on straight volume. Given the
projected tightness in the distillate market and relative excess supply
in the gasoline market in the coming years, allowing the market to
choose freely may be important to overall fuel supply. In the extreme,
the cellulosic biofuel standard could then be met by roughly 10 billion
gallons of a cellulosic diesel fuel instead of the 16 billion gallons
of cellulosic ethanol assumed for the impacts analysis of this
proposal. The same amount of petroleum energy would be displaced, but
by different physical volumes.
As discussed above, there are no provisions in EISA that explicitly
instruct the Agency to change from the approach to Equivalence Values
adopted in RFS1. However, there is a question of how to address the
biomass-based diesel requirement under such an approach. In that
context, it does appear that Congress intended the required volumes of
biomass-based diesel to be treated as diesel volumes rather than
ethanol-equivalent volumes. Therefore EPA proposes that, for the
biomass-based diesel volume mandate under an ethanol-equivalent energy
content approach to Equivalence Values, the compliance calculations
would be structured such that this requirement is treated in effect as
a straight volume-based requirement.\25\
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\25\ The proposed regulations and the ensuing discussion in
Sections III and IV of this proposal reflect straight volume
approach, however, the impacts analysis of the program are
calculated using volumes based on ethanol-equivalent energy content.
Were we to maintain the energy content approach to Equivalence
Values, then we believe the biomass-based diesel standard should be
treated in effect as a biodiesel volume, reflecting the nature of
this standard, while the other three standards would be treated as
ethanol-equivalent volumes. In order to effectuate this, we are
considering two approaches. Under either approach all RINs would be
generated based on ethanol-equivalent volume, including biomass-
based diesel RINs. Under one approach, we would propose that the
biomass-based diesel standard also be expressed as an ethanol-
equivalent volume (e.g., 1.5 billion ethanol-equivalent gallons in
2012). Another approach would be to have the standard expressed as a
volume of biomass-based diesel, and to require the biomass-based
diesel RINs be adjusted back to a volume basis, with this adjustment
just for purposes of the biomass-based diesel standard but not for
purposes of the other fuels mandates. Either approach would have the
same result.
---------------------------------------------------------------------------
In addition, it is also clear that Congress established the
advanced biofuel standard in EISA to begin to take affect in 2009.
However, if we maintain the ethanol-equivalent energy content approach
for RFS2, and biodiesel continues to have an Equivalence Value of 1.5,
then from 2009-2012 the combination of the biomass-based diesel
standard and the cellulosic biofuel standard will meet or exceed the
advanced biofuel standard. Unless we were to waive a portion of either
the biomass-based diesel standard or the cellulosic biofuel standard,
the advanced biofuel standard would not have an independent effect
until 2013. While EPA recognizes this, EPA believes that the long term
benefits of an energy based Equivalence Value may be significantly
greater than any temporary diminishment in the real world impact of the
advanced biofuel mandate.
In recognition of the competing perspectives, we request comment on
both co-proposed approaches to the Equivalence Values: (1) Retaining
the energy-based approach of the RFS1 program, and (2) a straight
volume approach measured in liquid gallons of renewable fuel.
2. Fuel Pathways and Assignment of D Codes
As described in Section III.A, we propose that RINs under RFS2
would continue to have the same number of digits and code definitions
as under RFS1. The one change would be that, while the D code would
continue to identify the standard to which the RIN could be applied, it
would be modified to have four values corresponding to the four
different renewable fuel categories defined in EISA. These four D code
values and the corresponding categories are shown in Table III.A-1.
In order to generate RINs for renewable fuel that meets the various
eligibility requirements (see Section III.B), a producer or importer
must know which D code to assign to those RINs. We propose that a
producer or importer would determine the appropriate D code using a
lookup table in the regulations. The lookup table would list various
combinations of fuel type, production process, and feedstock, and the
producer or importer would choose the appropriate combination
representing the fuel he is producing and for which he is generating
RINs. Parties generating RINs would be required to use the D code
specified in the lookup table and would not be permitted to use a D
code representing a broader renewable fuel category. For example, a
party whose fuel qualified as biomass-based diesel could not choose to
categorize that fuel as advanced biofuel or general renewable fuel.
This section describes our proposed approach to the assignment of D
codes to RINs for domestic producers, foreign producers, and importers
of renewable fuel. Subsequent sections address the generation of RINs
in special circumstances, such as when a production facility has
multiple applicable combinations of feedstock, fuel type, and
production process within a calendar year, production facilities that
co-process renewable biomass and fossil fuels, and production
[[Page 24946]]
facilities for which the lookup table does not provide an applicable D
code.
a. Domestic Producers
For domestic producers, the lookup table would identify individual
fuel ``pathways'' comprised of unique combinations of the type of
renewable fuel being produced, the feedstock used to produce the
renewable fuel, and a description of the production process. Each
pathway would be assigned to one of the four specific D codes on the
basis of the revised renewable fuel definitions provided in EISA and
our assessment of the GHG lifecycle performance for that pathway. A
description of the lifecycle assessment of each fuel pathway and the
process we used for determining the associated D code can be found in
Section VI. Note that the subsequent generation of RINs would also
require as a prerequisite that the feedstocks used to make the
renewable fuel meet the definition of ``renewable biomass'' as
described in Section III.B.4, including applicable land use
restrictions. Moreover, a domestic producer could not introduce
renewable fuel into commerce without generating RINs unless he had
records demonstrating that the feedstocks used to produce the fuel did
not meet the definition of renewable biomass. See Section III.B.4.b.ii
for further discussion of this issue.
Through our assessment of the lifecycle GHG impacts of different
pathways and the application of the EISA definitions for each of the
four categories of renewable fuel, including the GHG thresholds, we
have determined that all four categories would have pathways that could
be used to meet the Act's volume requirements. For example, ethanol
made from corn stover or switchgrass in an enzymatic hydrolysis process
would count as cellulosic biofuel. Biodiesel made from waste grease
could count as biomass-based diesel. Ethanol made from sugarcane sugar
may count as advanced biofuel depending on the results of the lifecycle
assessment conducted for the final rule and a determination about
whether the GHG threshold for advanced biofuel should be adjusted
downward. Finally, under an assumed 100-year timeframe and 2% discount
rate for GHG emissions impacts, a variety of pathways would count as
generic renewable fuel under the RFS2 program, including ethanol made
from corn starch in a facility powered by biomass combustion and
biodiesel made from soybean oil. The complete list of pathways that
would be valid under our proposed RFS program is provided in the
regulations at Sec. 80.1426(d), based upon an assumed 100-year
timeframe and 2% discount rate for GHG emission impacts.
Domestic producers would choose the appropriate D code from the
lookup table in the regulations based on the fuel pathway that
describes their facility. The fuel pathway must be specified by the
producer in the registration process as described in Section III.C. If
there were changes to a domestic producer's facility or feedstock such
that their fuel would require a D code that was different from any D
code(s) which their existing registration information already allowed,
the producer would be required to revise its registration information
with EPA 30 days prior to changing the applicable D code it uses to
generate RINs. Situations in which multiple fuel pathways could apply
to a single facility are addressed in Section III.D.3 below.
For producers for whom none of the defined fuel pathways in the
lookup table would apply, we propose two possible treatments. First,
such producers may be able to generate RINs through our proposed system
of default D codes as described in Section III.D.5 below. Second, if a
producer meets the criteria for grandfathered status as described in
Section III.B.3 and his fuel meets the definition of renewable fuel as
described in Section III.B.1, he could continue to generate RINs for
his fuel but would use a D code of 4 for those RINs generated under the
grandfathering provisions. If a producer was not covered by either of
these two treatments, we propose that he would not be permitted to
generate RINs for his product until the lookup table in the regulations
was modified to include a pathway applicable to his operations.
A diesel fuel product produced from cellulosic feedstocks that
meets the 60% GHG threshold could qualify as either cellulosic biofuel
or biomass-based diesel. As a result, we are proposing that the
producer of such ``cellulosic diesel'' be given the choice of whether
to categorize his product as either cellulosic biofuel or biomass-based
diesel. This would allow the producer to market his product and the
associated RINs on the basis of market demand. However, we request
comment on an alternative approach as shown in Table III.D.2.a-1 in
which an additional D code would be defined to represent cellulosic
diesel and an obligated party would be given the choice of using
cellulosic diesel RINs either to meet his or her RVO for cellulosic
biofuel or for biomass-based diesel.
Table III.D.2.a-1--Alternative D Code Definitions To Accommodate
Cellulosic Diesel
------------------------------------------------------------------------
D value Meaning under RFS1 Meaning under RFS2
------------------------------------------------------------------------
1............................... Cellulosic biomass Cellulosic
ethanol. biofuel.
2............................... Any renewable fuel Biomass-based
that is not diesel.
cellulosic
biomass ethanol.
3............................... Not applicable.... Cellulosic biofuel
or biomass-based
diesel.
4............................... Not applicable.... Advanced biofuel.
5............................... Not applicable.... Renewable fuel.
------------------------------------------------------------------------
Under this alternative, producers of cellulosic diesel would assign
a D code of 3 to their product rather than being given a choice of
whether to assign a D code of 1 or 2. Any obligated party that acquired
a RIN with a D code of 3 could apply that RIN to either its cellulosic
biofuel or biomass-based diesel obligation, but not both. The advantage
of this alternative approach is that it reflects the full compliance
value for the product, and hence its potential value to an obligated
party. The obligated party is then given the ability to make a choice
about how to treat cellulosic diesel based on the market price and
availability of RINs with D codes of 1 and 2. We request comment on
this alternative approach to the designation of D codes for cellulosic
diesel.
b. Foreign Producers
Under RFS1, foreign producers have the option of generating RINs
for the renewable fuel that they export to the U.S. if they want to
designate their fuel as cellulosic biomass ethanol or waste-derived
ethanol, and thereby take advantage of the additional 1.5 credit value
afforded by the 2.5 Equivalence Value for such products. In order to
[[Page 24947]]
ensure that EPA has the ability to enforce the regulations relating to
the generation of RINs from such foreign ethanol producers, the RFS1
regulations require them to post a bond and submit to third-party
engineering reviews of their production process. If a foreign producer
does not generate RINs for the renewable fuel that it exports to the
U.S., the U.S. importer is responsible for generating the RINs
associated with the imported renewable fuel.
EISA creates unique challenges in the implementation and
enforcement of the renewable fuel standards for imported renewable
fuel. Unlike our other fuels programs, EPA cannot determine whether a
particular shipment of renewable fuel is eligible to generate RINs
under the new program by testing the fuel itself. Instead, information
regarding the feedstock that was used to produce renewable fuel and the
process by which it was produced is vital to determining the proper
renewable fuel category and RIN type for the imported fuel. It is for
these reasons that we required foreign producers of cellulosic biomass
ethanol or waste-derived ethanol under RFS1 to take additional steps to
ensure the validity of the RINs they generate.
For RFS2 we are proposing a similar approach to that taken under
RFS1, but with a number of modifications to account for the changes
that EISA makes to the definition of renewable fuel. Thus, we propose
that foreign producers would have the option of generating RINs for any
renewable fuel (not just the cellulosic biofuel category) that they
export to the U.S. If the foreign producer did not generate RINs, the
importer would be required to generate RINs for the imported renewable
fuel. Our proposed importer provisions are covered in more detail in
Section III.D.2.c below.
In general, we propose that foreign producers of renewable fuel who
intend to export their fuel to the U.S. would use the same process as
domestic producers to generate RINs, namely the lookup table to
identify the appropriate D code as a function of fuel type, production
process, and feedstock. They would be required to be registered with
the EPA as a producer under the RFS2 program and would be subject to
the same recordkeeping, reporting, and attest engagement requirements
as domestic producers, including those provisions associated with
ensuring that the feedstocks they use meet the definition of renewable
biomass. They would also be required to submit to third-party
engineering reviews of their production process and use of feedstocks,
just as domestic producers are. As under the RFS1 program, the foreign
producer would also be required to comply with additional requirements
designed to ensure that enforcement of the regulations at the foreign
production facility would not be compromised. For instance, foreign
producers would be required to designate renewable fuel intended for
export to the U.S. as such and segregate the volume until it reaches
the U.S. in order to ensure that RINs are only generated for volumes
imported into the U.S. Foreign producers would also be required to post
a bond to ensure that penalties can be assessed in the event of a
violation. Moreover, as a regulated party under the RFS2 program,
foreign producers must allow for potential visits by EPA enforcement
personnel to review the completeness and accuracy of records and
registration information. Non-compliance with any of these requirements
could be grounds for refusing to allow renewable fuel from such a
foreign producer to be imported into the U.S.
For RFS2, we are proposing a number of additional provisions to
address foreign companies that produce renewable fuel for export to the
United States, but that do not generate their own RINs for that
renewable fuel. These provisions are intended to account for the
greater difficulties in verifying the validity of RINs for imported
renewable fuel when the importer is generating the RINs, given that the
importer would generally not have direct knowledge of the feedstocks
used to produce the renewable fuel, the land used to grow those
feedstocks, or the fuel production process. We believe that these
additional provisions would be necessary to ensure that RINs
representing imported renewable fuel and used by obligated parties have
been generated appropriately.
As described more fully in Section III.D.2.c below, importers would
only be allowed to import renewable fuel from registered foreign
producers and would be required to generate RINs for all imported
renewable fuel that has not been assigned RINs by the foreign producer.
Like domestic and foreign producers who generate RINs, the importer
must be able to determine if the renewable biomass definition has been
met before generating RINs. The importer must also have enough
information about the production process and feedstock to be able to
use the lookup table to identify the appropriate D code to include in
the RINs he generates. Since the foreign producer is the only party who
can provide this information, we believe that it would be appropriate
to require the foreign producer of any renewable fuel exported to the
U.S. to provide this information to the U.S. importer before the
renewable fuel enters U.S. commerce even if the foreign producer is not
generating RINs himself. Moreover, the foreign producer should be
liable for the accuracy of this information just as if he were the
party generating RINs. Therefore, in order to ensure that RINs are
valid regardless of who generates them, we propose that all the
provisions described above that would be applicable to a foreign
producer who generates RINs would also apply to a foreign producer who
does not generate RINs but still exports renewable fuel to the U.S.
This would include registration with the EPA under the RFS2 program,
being subject to all the recordkeeping, reporting, and attest
engagement requirements, and posting a bond. The only exception would
be that the foreign producer would not be required to segregate a
specific volume between the foreign producer's facility and the import
facility if the foreign producer is not generating RINs, since the
importer would be the primary party responsible for measuring the
volume before generating RINs.
Although we are proposing that RINs for imported renewable fuel
could be generated by either the importer or the foreign producer, it
is possible that this could result in difficulty in verifying that only
one set of RINs has been generated for a given volume of renewable
fuel. One possible solution would be to require a foreign producer to
make a decision regarding RIN generation that would apply for an entire
calendar year. Under this approach, a foreign producer would be
required to either generate RINs for all the renewable fuel that he
exports to the U.S within a calendar year, or to generate no RINs for
the renewable fuel that he exports to the U.S within a calendar year.
While we are not proposing this approach it today's action, we request
comment on it.
As described in Section III.B.4.b.ii, we are proposing that
domestic producers could only introduce renewable fuel into commerce
without generating RINs if they demonstrate that feedstocks used to
produce the fuel did not meet the definition of renewable biomass. Thus
it would not be sufficient for a domestic producer to simply fail to
make a demonstration that the renewable biomass definition had been
met, and thereby avoid generation of RINs. We propose that a similar
approach would be applied to imported renewable fuel. As a result, all
renewable fuel that would be imported into the U.S. would be required
to come with
[[Page 24948]]
documentation regarding the status of the feedstock's compliance with
the renewable biomass definition. In the case of documentation
indicating that the renewable biomass definition had been met, the
importer would be required to generate RINs. In the case of
documentation indicating that the renewable biomass definition had not
been met, the importer would be prohibited from generating RINs but
could still import the renewable fuel into the U.S. Renewable fuel that
was not accompanied by any documentation regarding the status of the
feedstock's compliance with the renewable biomass definition could not
be imported into the U.S.
Our proposed approach to foreign producers is consistent with the
approach we propose taking for domestic producers, in that the producer
is responsible for ensuring that RINs generated for renewable fuel used
in the U.S. are valid and categorized appropriately. While our proposed
approach to foreign producers of renewable fuel under RFS2 would
require additional actions in comparison to their general requirements
under RFS1, we believe these provisions would be necessary to ensure
that the volume mandates shown in Table II.A.1-1 are met, given the new
definitions for renewable fuel and renewable biomass in EISA. We
request comment on our proposed approach to foreign producers.
c. Importers
Under RFS1, importers who import more than 10,000 gallons in a
calendar year must generate RINs for all imported renewable fuel based
on its type, except for cases in which the foreign producer generated
RINs for cellulosic biomass ethanol or waste-derived ethanol. Due to
the new definitions of renewable fuel and renewable biomass in EISA,
importers could no longer generate RINs under RFS2 on the basis of fuel
type alone. Instead, they must be able to determine whether or not the
renewable biomass definition has been met for the renewable fuel they
intend to import, and they must also have sufficient information about
the feedstock and process used to make the renewable fuel to allow them
to identify the appropriate D code from the lookup table for use in the
RINs they generate. As described in Section III.D.2.b above, we are
proposing that in order for an importer to import renewable fuel into
the U.S., the foreign producer would have to provide this information
to the importer.
Under today's proposal, importers would be able to import renewable
fuels only under one of the following scenarios:
1. The importer receives RINs generated by the registered foreign
producer when he imports a volume of renewable fuel.
2. The imported renewable fuel is not accompanied by RINs generated
by the registered foreign producer, and the foreign producer provides
the importer with:
--A demonstration that the renewable biomass definition has been met
for the volume of renewable fuel being imported.
--Information about the feedstock and production process used to
produce the renewable fuel.
In this case, the importer would be required to generate RINs for
the imported renewable fuel before introducing it into commerce in the
contiguous 48 states or Hawaii.
3. The imported renewable fuel is not accompanied by RINs generated
by the registered foreign producer, and the foreign producer provides
the importer with a demonstration that the renewable biomass definition
has not been met for the volume of renewable fuel being imported. See
further discussion of this issue in Section III.B.4.b.ii. The importer
would be prohibited from generating RINs for the imported volume, but
could still introduce the renewable fuel into commerce.
If none of these scenarios applied, the importer would be
prohibited from importing renewable fuel. Our proposed approach to
imported fuels would apply to both neat renewable fuel and renewable
fuels blended into gasoline or diesel.
As described in Section III.B.4.e, we also seek comment on an
alternative approach to imported renewable fuel in which foreign
renewable fuel producers would have the option of not participating in
RFS2 but still export renewable fuel to the U.S. Under this alternative
approach, foreign producers would have to meet requirements for
segregating their fuel from renewable fuel for which RINs were
generated, and the importer of their fuel would be required to track it
to ensure that the fuel remains segregated in the U.S. and is not used
by a domestic company for illegal RIN generation.
While it is important that all RINs be based on accurate
information about the feedstocks and production process used to produce
the renewable fuel, it may not be necessary to place the burden upon
importers for acquiring this information before they generate RINs.
Instead, an alternative approach would prohibit importers from
generating any RINs, and instead require foreign producers to generate
RINs for all renewable fuel that they export to the U.S. We recognize
that this would be a significant change from RFS1, and thus we are not
proposing it. However, since it would place the same responsibilities
on foreign producers as domestic producers, we request comment on it.
3. Facilities With Multiple Applicable Pathways
If a given facility's operations can be fully represented by a
single pathway, then a single D code taken from the lookup table will
be applicable to all RINs generated at or imported into that facility.
However, we recognize that this will not always be the case. Some
facilities use multiple feedstocks at the same time, or switch between
different feedstocks over the course of a year. A facility may be
modified to produce the same fuel but with a different process, or may
be modified to produce a different type of fuel. Any of these
situations could result in multiple pathways being applicable to a
facility, and thus there may be more than one D code used for various
RINs generated at the facility.
If more than one pathway applies to a facility within a compliance
period, no special steps would need to be taken if the D codes were the
same for all the applicable pathways. In this case, all RINs generated
at the facility would have the same D code. As for all other producers,
the producer with multiple applicable pathways would describe its
feedstock(s), fuel type(s), and production process(es) in its annual
report to the Agency so that we could verify that the D code used was
appropriate.
However, if more than one pathway applies to a facility within a
compliance period and these pathways have been assigned different D
codes, then the producer must determine which D codes to use when
generating RINs. There are a number of different ways that this could
occur, and our proposed approach to designating D codes for RINs in
these cases is described in Table III.D.3-1.
[[Page 24949]]
Table III.D.3-1--Proposed Approach To Assigning Multiple D Codes for
Multiple Applicable Pathways
------------------------------------------------------------------------
Case Description Proposed approach
------------------------------------------------------------------------
1............................... The pathway The applicable D
applicable to a code used in
facility changes generating RINs
on a specific must change on
date, such that the date that the
one single fuel produced
pathway applies changes pathways.
before the date
and another
single pathway
applies on and
after the date.
2............................... One facility The volumes of the
produces two or different types
more different of renewable fuel
types of should be
renewable fuel at measured
the same time. separately, with
different D codes
applied to the
separate volumes.
3............................... One facility uses For any given
two or more batch of
different renewable fuel,
feedstocks at the the producer
same time to should assign the
produce a single applicable D
type of renewable codes using a
fuel. ratio (explained
below) defined by
the amount of
each type of
feedstock used.
------------------------------------------------------------------------
In general, we are not aware of a scenario in which a facility uses
two different processes in parallel to convert a single type of
feedstock into a single type of renewable fuel. Therefore, we have not
created a case in Table III.D.3-1 to address it. However, we know that
some corn-ethanol facilities may dry only a portion of their
distiller's grains and leave the remainder wet. Using the lifecycle
with an assumed 100 year timeframe and 2% discount rate for GHG
emission impacts, the treatment of the distiller's grains could impact
the determination of whether the 20% GHG threshold for renewable fuel
has been met, a corn-ethanol facility that dries some portion of its
distiller's grains would need to implement additional technologies in
order to qualify to generate RINs for all the ethanol it produces (if
the facility has not been grandfathered). The lifecycle analyses
conducted for this proposal only examined cases in which a corn-ethanol
facility dried 100% of its distiller's grains or left 100% of its
distiller's grains wet. As a result, a corn-ethanol facility that dried
only a portion of its distiller's grain would be treated as if it dried
100% of its grains, and would thus need to implement additional GHG-
reducing technologies as described in the lookup table in order to
qualify to generate RINs. This is reflected in the list of required
production technologies in the lookup table at Sec. 80.1426(d) for
facilities that dry any portion of their distiller's grains. In
practice, depending on the selection of other technologies, it may be
possible for a facility using some combination of dry and wet
distiller's grains to meet the 20% GHG threshold. Therefore we request
comment on whether a selection of pathways should be included in the
lookup table that represent corn-ethanol facilities that dry only a
portion of their distiller's grains. We also request comment on whether
RINs could be assigned to only a portion of the facility's ethanol in
cases wherein only a portion of the distiller's grains are dried.
We propose that the cases listed in Table III.D.3-1 be treated as
hierarchical, with Case 2 only being used to address a facility's
circumstances if Case 1 is not applicable, and Case 3 only being used
to address a facility's circumstances if Case 2 is not applicable. We
believe that this approach covers all likely cases in which multiple
applicable pathways may apply to a renewable fuel producer. Some
examples in which Case 2 or 3 would apply are provided in Table
III.D.3-2.
Table III.D.3-2--Examples of Facilities With Multiple Pathways
------------------------------------------------------------------------
Applicable
Example case Reasoning
------------------------------------------------------------------------
Facility makes both diesel and 2 The production of two
naphtha (a gasoline blendstock) types of renewable
from gasified biomass in a Fischer- fuel from the same
Tropsch process. feedstock and process
makes it highly
likely that the two
pathways would be
assigned the same D
code. If LCA
determined that this
was not the case, the
volumes of diesel and
naphtha can be
measured separately
and assigned separate
batch-RINs with
different D codes.
Facility produces ethanol from corn 3 There is only one fuel
starch and corn cobs/husks. produced, so Case 2
cannot apply.
Facility makes both ethanol and 2 Case 2 is the default
butanol through two different since there are two
processes using corn starch. separate fuels
produced. However,
Case 3 would not
apply regardless
because there is only
one feedstock.
Facility makes ethanol through an 3 There is only one fuel
enzymatic hydrolysis process using produced, so Case 2
both switchgrass and corn stover. cannot apply.
------------------------------------------------------------------------
A facility where two or more different types of feedstock were used
to produce a single fuel (such as Case 3 in Table III.D.3-1) would be
required to generate two or more separate batch-RINs \26\ for a single
volume of renewable fuel, and these separate batch-RINs would have
different D codes. The D codes would be chosen on the basis of the
different pathways as defined in the lookup table in Sec. 80.1426(d).
The number of gallon-RINs that would be included in each of the batch-
RINs would depend on the relative amount of the different types of
feedstocks used by the facility. We propose to use the useable energy
content of the feedstocks to determine how many gallon-RINs should be
assigned to each D code. Our proposed calculations are given in the
regulations at Sec. 80.1126(d)(5).
---------------------------------------------------------------------------
\26\ Batch-RINs and gallon-RINs are defined in the RFS1
regulations at 40 CFR 80.1101(o).
---------------------------------------------------------------------------
In determining the useable energy content of the feedstocks, we
propose to take into account several elements to ensure that the number
of gallon-RINs associated with each D code is appropriate. For
instance, we propose
[[Page 24950]]
that only that portion of a feedstock which is expected to be converted
into renewable fuel by the facility should be counted in the
calculation. For example, a biochemical cellulosic ethanol conversion
process that could not convert the lignin into ethanol would not
include the lignin portion of the biomass in the calculation. This
approach would also take into account the conversion efficiency of the
facility. We propose that the producer of the renewable fuel would be
required to designate this fraction for the feedstocks processed by his
facility and to include this information as part of its reporting
requirements.
We are also proposing to use the energy content of the feedstocks
instead of their mass since we believe that their relative energy
contents are more closely related than their mass to the energy in the
renewable fuel. Producers would be required to designate the energy
content (in Btu/lb) of the portion of each of their feedstocks which is
converted into fuel. We request comment on whether producers would
determine these values independently for their own feedstocks, or
whether a standard set of such values should be developed and
incorporated into the regulations for use by all renewable fuel
producers. If we did specify a standard set of energy content values,
we request comment on what those values should be and/or the most
appropriate sources for determining those values.
Some components in the calculation of the useable energy content of
feedstocks are unlikely to vary significantly for a particular type of
feedstock. This would include that portion of a feedstock which is
expected to be converted into renewable fuel by the facility, and the
relative amount of energy in the two feedstocks. For these factors, we
propose that one set of values be determined by the producer and
applied to all renewable fuel production within a calendar year. The
values could be reassessed annually and adjusted as necessary.
Although we are proposing annual determinations of the portion of a
feedstock which is expected to be converted into renewable fuel by the
facility and the relative amount of energy in the two feedstocks, we
are proposing daily determinations of the total mass of each type of
feedstocks used by the facility. This approach would take into account
the fact that the relative amount of the different feedstocks used
could vary frequently, and thus the determination of the total useable
energy content of the feedstocks would be unique to the renewable fuel
produced each day. We believe that renewable fuel producers would have
ready access to information about total feedstock mass used each day,
such that the timely generation of RINs should not be unduly affected.
We request comment on the effort and time involved in collecting
information on feedstock mass and translating this information on a
daily basis into RINs assigned to volumes of renewable fuel.
In order to generate RINs when the processing of two or more
different feedstocks in the same facility results in two or more
different applicable D codes but a single renewable fuel, the producer
would continue to determine the total number of gallon-RINs that must
be generated for and assigned to a given volume of renewable fuel using
the process established under RFS1. In short, the total volume of the
renewable fuel would be multiplied by its Equivalence Value. However,
the feedstock's useable energy content would be used to divide the
resulting number of gallon-RINs into two or more groups, each
corresponding to a different D code. Two, three, or more separate
batch-RINs could then be generated and assigned to the single volume of
renewable fuel. The sum of all gallon-RINs from the different batch-
RINs would be equal to the total number of gallon-RINs that must be
generated to represent the volume of renewable fuel.
As described in Section III.J, we propose that in their reports,
producers of renewable fuel be required to submit information on the
feedstocks they used, their production processes, and the type of
fuel(s) they produced during the compliance period. This would apply to
both domestic producers and foreign producers who export any renewable
fuel to the U.S. We would use this information to verify that the D
codes used in generating RINs were appropriate.
4. Facilities That Co-Process Renewable Biomass and Fossil Fuels
We expect situations to arise in which a producer uses a renewable
feedstock simultaneously with a fossil fuel feedstock, producing a
single fuel that is only partially renewable. For instance, biomass
might be cofired with coal in a coal-to-liquids (CTL) process that uses
Fischer-Tropsch chemistry to make diesel fuel, biomass and waste
plastics might be fed simultaneously into a catalytic or gasification
process to make diesel fuel, or vegetable oils could be fed to a
hydrotreater along with petroleum to produce a diesel fuel. In these
cases, the diesel fuel would be only partially renewable. We propose
that RINs must be generated in such cases, but in such a way that the
number of gallon-RINs corresponds only to the renewable portion of the
fuel.
Under RFS1, we created a provision to address the co-processing of
``renewable crudes'' along with petroleum feedstocks to produce a
gasoline or diesel fuel that is partially renewable. See 40 CFR
80.1126(d)(6). However, this provision would not apply in cases where
either the renewable feedstock or the fossil fuel feedstock is a gas
(e.g., biogas, natural gas) or a solid (e.g. biomass, coal). Therefore,
we propose to eliminate the existing provision applicable only to
liquid feedstocks and replace it with a more comprehensive approach
that could apply to liquid, solid, or gaseous feedstocks and any type
of conversion process. Our proposed approach would be similar to the
treatment of renewable fuels with multiple D codes as described in
Section III.D.3 above. Thus, the producer would determine the renewable
fuel volume that would be assigned RINs based on the amount of energy
in the renewable feedstock relative to the amount of energy in the
fossil feedstock. Just as two different batch-RINs would be generated
for a single volume of renewable fuel produced from two different
renewable feedstocks, only one batch-RIN would be generated for a
single volume of renewable fuel produced from both a renewable
feedstock and a fossil feedstock, and this one batch-RIN would be based
on the contribution that the renewable feedstock makes to the volume of
renewable fuel. See Sec. 80.1426(d)(6) for our proposed calculations
under these circumstances.
For facilities that co-process renewable biomass and fossil fuels
to produce a single fuel that is partially renewable, we propose to use
the relative energy in the feedstocks to determine the number of
gallon-RINs that should be generated. As shown in the regulations at
Sec. 80.1426(d)(6), the calculation of the relative energy contents
would include factors that take into account the conversion efficiency
of the plant, and as a result, potentially different reaction rates and
byproduct formation for the various feedstocks would be accounted for.
The relative energy content of the feedstocks would be used to adjust
the basic calculation of the number of gallon-RINs downward from that
calculated on the basis of fuel volume alone. The D code that would be
assigned to the RINs would be drawn from the lookup table in the
regulations as if the feedstock was entirely renewable biomass. Thus,
for instance, a coal-to-liquids plant that co-processes some cellulosic
biomass to make diesel fuel would be treated as a plant that
[[Page 24951]]
produces only cellulosic diesel for purposes of identifying the
appropriate D code.
One drawback of our proposed approach is that it does nothing to
address lifecycle GHG emissions associated with the portion of the fuel
that comes from the fossil fuel feedstock. While the lifecycle GHG
thresholds under RFS2 are specific to fuels made from renewable
biomass, allowing a fuel producer to generate RINs for the co-
processing of renewable biomass with fossil fuels might provide a
greater incentive for production of transportation fuels from processes
that have high lifecycle GHGs. In such cases, the GHG benefits of the
renewable fuel may be overwhelmed by the GHG increases of the fossil
fuel. This is of particular concern for CTL processes which generally
produce higher lifecycle GHG emissions per unit of transportation fuel
produced than traditional refinery processes that use petroleum. Under
our proposed approach to the treatment of co-processing of renewable
biomass and fossil fuels, incentives would be provided for renewable
fuels with lower lifecycle GHG emissions, but there will be little
disincentive for production of high GHG-emitting fuels made from fossil
fuels.
As an alternative to our proposed approach, we could treat fuels
produced through co-processing of renewable biomass and fossil fuel
feedstocks in an aggregate fashion rather than focusing only on the
renewable portion of those fuels. In this approach, we would require
the whole fuel produced at co-processing facilities to meet the
lifecycle GHG thresholds under RFS2. If, for instance, a diesel fuel
produced from co-processing renewable biomass and coal in a Fischer-
Tropsch process were determined to not meet the 20% GHG threshold, no
RINs could be generated even though the renewable portion of the diesel
fuel might meet the 20% GHG threshold. However, this alternative
approach would require a lifecycle analysis that is specific to the
relative amounts of renewable biomass and fossil fuel feedstock being
used at a particular facility, which would in turn require a facility-
specific lifecycle GHG model. As described in Section II.A.3, this is
beyond the capabilities of our current modeling tools. Moreover, this
alternative approach could have undesirable effects on facilities that
produce renewable fuel from multiple renewable feedstocks. For
instance, if a facility produced ethanol from both corn starch and corn
stover and the lifecycle GHG assessment was conducted for this specific
facility as a whole, it might not meet the 60% GHG threshold for
cellulosic biofuel. As a result, the portion of the ethanol produced
from corn stover could not be counted as cellulosic biofuel but would
instead count only as renewable fuel, even though our lifecycle
analyses have determined that ethanol from corn stover does meet the
60% GHG threshold. Nevertheless, we seek comment on this alternative
approach.
As another alternative to using the relative energy in the
feedstocks to determine the number of gallon-RINs that should be
generated, we could allow renewable fuel producers to use an accepted
test method to directly measure the fraction of the fuel which
originates with biomass rather than a fossil fuel feedstock. For
instance, ASTM test method D-6866 can be used to determine the
renewable content of gasoline. However, such a test method could not
distinguish between fuel made from feedstocks that meet the definition
of renewable biomass, and other biomass feedstocks which do not meet
the definition of renewable biomass. We request comment on the use of
ASTM D-6866 or equivalent test methods to determine the number of RINs
generated when multiple feedstocks are used simultaneously to make a
fuel.
5. Treatment of Fuels Without an Applicable D Code
Among all fuels covered by our proposed RFS2 program, we have
identified a number of specific ``pathways'' of fuels, defined by fuel
type, feedstock, and various production process characteristics. This
list includes fuels that either already exist in the marketplace or are
expected to exist sometime during the next decade, and for which we had
sufficient information to conduct a lifecycle analysis of the GHG
emissions. As described in III.D.2, we have assigned each pathway a D
code corresponding to the four categories of renewable fuel defined in
EISA.
Despite our efforts to explicitly address the existing or possible
pathways in our proposed program, it is expected that a fuel, process,
or feedstock will arise that is a renewable fuel meeting the RFS
definitions, and yet is not among the fuels we explicitly identified in
the regulations as a RIN-generating fuel. This could occur for an
entirely new fuel type, a known fuel produced from a new feedstock, or
a known fuel produced through a unique production process. In such
cases, the fuel may meet our definition of renewable fuel covered under
our program, but would not have been assigned the appropriate D code in
the regulations. To address some of these fuel pathways, we are
proposing the use of default D codes.\27\
---------------------------------------------------------------------------
\27\ Additional default requirements applicable to importers of
renewable fuels are discussed in Section III.D.2.c.
---------------------------------------------------------------------------
Under our proposed approach, the producer would be required to
register under the RFS program and provide information about their
facility as described in Section III.C. The producer will also be
required to provide any information necessary for EPA to perform a
proper lifecycle analysis. Additionally, the company would need to
register their renewable fuel under title 40 CFR part 79 as a motor
vehicle fuel. If EPA determines, based on the company's registration,
that they are not producing renewable fuel, the company will not be
able to generate RINs.
In order to generate RINs, the producer of renewable fuel would
apply through our registration system to use the D code that best
represents his combination of fuel type, feedstock, and production
process. If the producer's combination of fuel type and feedstock, but
not production process, is represented in an already defined pathway
combination of fuels, processes, or feedstocks, the producer would use
the highest numerical D code applicable to the fuel and feedstock
combination. For example, if a fuel and feedstock spans the D Codes 3
and 4 then the producer would use 4 until the regulations were updated.
The producer then would generate RINs using the D code 4, until EPA
could perform a lifecycle analysis and issue a change to the
regulations to reflect the new pathway. If the producer is making a new
fuel or using a new feedstock that producer will still need to apply,
but would be unable to generate RINs until the regulations were updated
with the new pathway.
Since certain combinations of fuel, production process, and
feedstock have been determined through our lifecycle analysis to not
meet the minimum 20% GHG threshold, they would be ineligible to
generate RINs and EPA would not allow producers using those processes
to generate RINs using a default D code. To effectuate this, we propose
to provide a statement in the regulations of pathways that are
prohibited from using a default D code. For example, if a producer is
producing ethanol from cornstarch in a process that uses coal or
natural gas for process heat, then regardless of other elements of the
production process the producer may not use a default D code, but must
register and provide information
[[Page 24952]]
necessary to conduct a lifecycle analysis.
EPA will not conduct a rulemaking every year to adjust the
regulations for new fuels, processes, or feedstocks. EPA will
periodically update the regulations as necessary under CAA section
211(o)(4) and may take the opportunity to update the list of fuel
pathways. Companies are encouraged to work with EPA early to provide
information about fuels, processes, or feedstocks not in the
regulations so that we can do a proper lifecycle analysis before these
fuels, processes, or feedstocks are commercially viable. EPA is
proposing that if the regulations are not updated with in 5 years of
receipt of the application and the application is not rejected in that
time then the producer will no longer be able to generate RINs using a
default D code until the regulations are updated.
6. Carbon Capture and Storage (CCS)
One element of the production process that may enable renewable
fuel producers to greatly improve their GHG emissions is carbon capture
and storage (CCS). CCS involves the process of capturing CO2
from an industrial or energy-related source, transporting it to a
suitable storage site, and isolating it from the atmosphere for long
periods of time. While we are not proposing a specific pathway in
today's NPRM that would allow a renewable fuel producer to use CCS to
demonstrate compliance with the GHG thresholds, we believe that CCS
could be an effective method for significantly reducing the GHG
emissions associated with renewable fuel production.
Although there are several possible approaches for long-term
storage of CO2, this section will only address geologic
storage as a means to reduce CO2 emissions from renewable
fuel production facilities. This method entails injecting
CO2 deep underground and monitoring to ensure long-term
isolation from the atmosphere. The remainder of this section describes
the efforts to establish regulatory requirements for CCS, and the
further work that needs to be done before allowing the use of CCS as an
element in pathways eligible for generating RINs under the RFS2
program.
Although there is limited experience with integrated CCS systems in
the US, where CO2 is captured, transported and injected for
long-term storage, there are commercial CCS projects operating today
and several DOE pilot projects underway to further demonstrate CCS in a
variety of industrial sectors and geological settings. The EPA has been
working closely with DOE to collectively ensure that governmental
research programs address the range of potential environmental risks
associated with CCS and that appropriate regulatory frameworks are in
place to manage risks.\28\
---------------------------------------------------------------------------
\28\ More information on the EPA's UIC Program and ongoing
research into CCS issues is available at: http://www.epa.gov/safewater/uic/wells_sequestration.html.
---------------------------------------------------------------------------
The EPA has experience regulating underground injection of various
fluids and believes that well selected, designed, and managed sites can
sequester CO2 for long periods of time. The Safe Drinking
Water Act's (SDWA) Underground Injection Control (UIC) Program has been
successfully regulating tens of thousands of injection wells for over
35 years. The UIC program's siting, well construction, and monitoring
and testing requirements are keys to ensuring that injected fluids
remain in the geologic rock formations specifically targeted for
injection.
In March 2007, the EPA issued UIC permitting guidelines for pilot
geologic sequestration projects in order to ensure that these projects
could move forward under an appropriate regulatory framework.
Subsequently, on July 25, 2008, EPA issued a proposed rulemaking that
would address commercial-scale projects and establish the regulatory
requirements for underground injection of CO2 for the
purpose of geologic storage (73 FR 43492). These proposed regulations
include permitting requirements, criteria for establishing and
maintaining the mechanical integrity of wells, minimum criteria for
siting, injection well construction and operating requirements,
recordkeeping and reporting requirements, etc. While these regulations
cover many operational aspects of underground injection and monitoring
geologic sequestration sites, their purpose is to protect underground
sources of drinking water. The SDWA does not provide authority to
develop regulations for all areas related to CCS, including capture and
transport of CO2 and accounting or certification for GHG
emissions reductions. The UIC requirements will not replace or
supersede other statutory or regulatory requirements for protection of
human health and the environment. Thus, parties that implemented CCS
would still need to obtain all necessary permits from appropriate State
and Federal authorities under the Clean Air Act or any other applicable
statutes and regulations.
Specific areas that would need to be addressed before allowing the
renewable fuel producers to benefit from CCS in meeting GHG thresholds
include: the means through which the CO2 would be captured
from the renewable fuel production facility, the minimum fraction that
must be captured, appropriate means for transporting to the injection
site, and appropriate monitoring procedures to ensure long-term storage
of CO2. We believe the CO2 that would be most
readily available for capture in an ethanol production facility would
be that which is produced during the fermentation process, not
CO2 that is generated during the combustion of fossil fuels
for process energy, since CO2 from the fermentation process
provides a more concentrated stream that is more amenable to capture.
However, we request comment on the efficacy of capturing CO2
from the combustion of fossil fuels for process heat.
A mechanism for accounting for potential leakage of captured
CO2 during transport to the storage site or after injection
has occurred would also be required. The renewable fuel producer would
be responsible for tracking any leaks that occur after CO2
capture. We request comment on the type and level of surface and/or
subsurface monitoring that would be required to demonstrate long-term
storage of CO2. We also request comment on whether
additional monitoring and reporting requirements would be appropriate.
For example, whether there should be a requirement for the monitoring
and reporting of CO2 volumes captured, transported, injected
and stored, as well as any fugitive emissions released. We seek comment
on the appropriateness of establishing a performance standard for
CO2 leakage during transport, injection, and/or geologic
storage, and any data that might be available to help develop such a
performance standard.
Finally, in order to generate RINs, the renewable fuel producer
would have to, at minimum, demonstrate that a sufficient amount of
CO2 was sequestered to reach the appropriate lifecycle GHG
threshold. We expect that the regulations would need to specify the
minimum fraction of CO2 emitted that must be captured and
stored in order for a renewable fuel producer to qualify for generating
RINs. We request comment on whether this approach is appropriate.
E. Applicable Standards
CAA section 211(o)(3) describes how the applicable standards are to
be calculated. The only changes made to this provision by EISA are
substituting ``transportation fuel'' for gasoline, and reflecting the
expanded number of years
[[Page 24953]]
and additional renewable fuel categories added by Congress in CAA
211(o)(2). In general the form of the standard will not change under
RFS2. The renewable fuel standards will continue to be expressed as a
volume percentage, and will be used by each refiner, blender or
importer to determine their renewable volume obligations. The
applicable percentages are set so that if each regulated party meets
the percentages, then the amount of renewable fuel, cellulosic biofuel,
biomass-based diesel, and advanced biofuel used will meet the volumes
specified in Table II.A.1-1.\29\
---------------------------------------------------------------------------
\29\ Actual volumes can vary from the amounts required in the
statute. For instance, lower volumes may result if the statutorily
required volumes are adjusted downward according to the waiver
provisions in CAA 211(o)(7)(D). Also, higher or lower volumes may
result depending on the actual consumption of gasoline and diesel in
comparison to the projected volumes used to set the standards.
---------------------------------------------------------------------------
The new renewable fuel standards would be based on both gasoline
and diesel volumes as opposed to only gasoline. Under CAA section
211(o)(3), EPA must determine the refiners, blenders and importers who
are subject to the standard. We propose that the standard would apply
to refiners, blenders and importers of diesel in addition to gasoline,
for both highway and nonroad uses. As described more fully in Section
III.F.3, we are proposing at this time that other producers of
transportation fuel, such as producers of natural gas, propane, and
electricity from fossil fuels, would not be subject to the standard.
Since the standard would apply to refiners, blenders and importers of
gasoline and diesel, these are also the transportation fuels that would
be used to determine the annual volume obligation of the refiner,
blender or importer.
The projected volumes of gasoline and diesel used to calculate the
standards would continue to be provided by EIA's Short-Term Energy
Outlook (STEO). The standards applicable to a given calendar year would
be published by November 30 of the previous year. The renewable fuel
standards would also continue to take into account various adjustments.
For instance, gasoline and diesel volumes would be adjusted to account
for the required renewable fuel volumes, and gasoline and diesel
volumes produced by small refineries and small refiners would continue
to be exempt through 2010.
While the calculation methodology for determination of standards
would not change, there would be four separate standards under the new
RFS2 program, corresponding to the four separate volume requirements
shown in Table II.A.1-1. The specific formulas we propose using to
calculate the renewable fuel standards are described below in Section
III.E.1.
In order for an obligated party to demonstrate compliance, the
percentage standards would be converted into the volume of renewable
fuel each obligated party is required to satisfy. This volume of
renewable fuel is the volume for which the obligated party is
responsible under the RFS program, and would continue to be referred to
as its Renewable Volume Obligation (RVO). Since there would be four
separate standards under the RFS2 program, there would likewise be four
separate RVOs applicable to each refiner, importer, or other obligated
party. However, all RVOs would be determined in the same way as
described in the current regulations at Sec. 80.1107, with the
exception that each standard would apply to the sum of all gasoline and
diesel produced or imported as opposed to just the gasoline volume. The
formulas we propose using to calculate the RVOs under the RFS2 program
are described in Section III.G.1.
1. Calculation of Standards
a. How Would the Standards Be Calculated?
Table II.A.1-1 shows the required overall volumes of four types of
renewable fuel specified in EISA. The four separate renewable fuel
standards would be based primarily on (1) the 49-state \30\ gasoline
and diesel consumption volumes projected by EIA, and (2) the total
volume of renewable fuels required by EISA for the coming year. Each
renewable fuel standard will be expressed as a volume percentage of
combined gasoline and diesel sold or introduced into commerce in the
U.S., and will be used by each obligated party to determine its
renewable volume obligation.
---------------------------------------------------------------------------
\30\ Hawaii opted-in to the original RFS program; that opt-in is
carried forward to the proposed new program.
---------------------------------------------------------------------------
While we are proposing that the standards be based on the sum of
all gasoline and diesel, an alternative would split the standards
between those that would be specific to gasoline and those that would
be specific to diesel. To accomplish this, it would be necessary to
project the fraction of the volumes shown in Table II.A.1-1 for
cellulosic biofuel, advanced biofuel, and total renewable fuel that
would represent gasoline-displacing renewable fuel, and apply this
portion of the required volumes to gasoline (by definition the biomass-
based diesel standard would have no component relevant to gasoline).
The remaining portion would apply to diesel. The result would be seven
standards instead of four. This approach to setting standards would
more readily align the RFS obligations with the relative amounts of
gasoline and diesel produced or imported by each obligated party. For
instance, a refiner that produced only diesel fuel would have no
obligations under the RFS program for renewable fuels that are used to
displace gasoline. However, this alternative approach relies on
projections of the relative amounts of gasoline-displacing and diesel-
displacing renewable fuels that would need to be updated every year.
While such projections would be available through our proposed
Production Outlook Reports (see Section III.K), we nevertheless believe
that such an approach would unnecessarily complicate the program, and
thus we are not proposing it. However, we request comment on it.
In determining the applicable percentages for a calendar year, EISA
requires EPA to adjust the standard to prevent the imposition of
redundant obligations on any person and to account for renewable fuel
use during the previous calendar year by exempt small refineries,
defined as refineries that process less than 75,000 bpd of crude oil.
As a result, in order to be assured that the percentage standards will
in fact result in the volumes shown in Table II.A.1-1, we must make
several adjustments to what otherwise would be a simple calculation.
As stated, the renewable fuel standards for a given year are
basically the ratio of the amount of each type of renewable fuel
specified in EISA for that year to the projected 49-state non-renewable
combined gasoline and diesel volume for that year. While the required
amount of total renewable fuel for a given year is provided by EISA,
the Act requires EPA to use an EIA estimate of the amount of gasoline
and diesel that will be sold or introduced into commerce for that year
to determine the percentage standards. The levels of the percentage
standards would be reduced if Alaska or a U.S. territory chooses to
participate in the RFS2 program, as gasoline and diesel produced in or
imported into that state or territory would then be subject to the
standard.
As mentioned above, we are proposing that EIA's STEO continue to be
the source for projected gasoline, and now diesel, consumption
estimates. These volumes include renewable fuel use. In order to
achieve the volumes of renewable fuels specified in EISA, the gasoline
and diesel volumes used to
[[Page 24954]]
determine the standard must be the non-renewable portion of the
gasoline and diesel pools. In order to get total non-renewable gasoline
and diesel volumes, we must subtract the total renewable fuel volume
from the total gasoline and diesel volume. As with RFS1, the best
estimation of the coming year's renewable fuel consumption is found in
Table 11 (U.S. Renewable Energy Use by Sector: Base Case) of the STEO.
CAA section 211(o) exempts small refineries \31\ from the RFS
requirements until the 2011 compliance period. In RFS1, we extended
this exemption to the few remaining small refiners not already
exempted.\32\ Since EPA proposes that small refineries and small
refiners continue to be exempt from the program until 2011 under the
new RFS2 regulations, EPA will exclude their gasoline and diesel
volumes from the overall non-renewable gasoline and diesel volumes used
to determine the applicable percentages until 2011. EPA believes this
is appropriate because the percentage standards need to be based on the
gasoline and diesel subject to the renewable volume obligations, to
achieve the overall required volumes of renewable fuel. Because the
total small refinery and small refiner gasoline production volume is
expected to be fairly constant compared to total U.S. transportation
fuel production, we are proposing to estimate small refinery and small
refiner gasoline and diesel volumes using a constant percentage of
national consumption, as we did in RFS1. Using information from
gasoline batch reports submitted to EPA for 2006, EIA data, and input
from the California Air Resources Board regarding California small
refiners, we estimate that small refinery volumes constitute 11.9% of
the gasoline pool, and 15.2% of the diesel pool.
---------------------------------------------------------------------------
\31\ Under section 211(o) of the Clean Air Act, small refineries
are those with 75,000 bbl/day or less average aggregate daily crude
oil throughput.
\32\ See Section IV.B.2.
---------------------------------------------------------------------------
CAA section 211(o) requires that the small refinery adjustment also
account for renewable fuels used during the prior year by small
refineries that are exempt and do not participate in the RFS2 program.
Accounting for this volume of renewable fuel would reduce the total
volume of renewable fuel use required of others, and thus directionally
would reduce the percentage standard. However, as we discussed in RFS1,
the amount of renewable fuel that would qualify, i.e., that was used by
exempt small refineries and small refiners but not used as part of the
RFS program, is expected to be very small. In fact, these volumes would
not significantly change the resulting percentage standards. Whatever
renewable fuels small refineries and small refiners blend will be
reflected as RINs available in the market; thus there is no need for a
separate accounting of their renewable fuel use in the equations used
to determine the standards. We thus are proposing, as for RFS1, that
this value be zero.
Just as with their corresponding gasoline and diesel volumes,
renewable fuels used in Alaska or U.S. territories are not included in
the renewable fuel volumes that are subtracted from the total gasoline
and diesel volume estimates. Section 211(o) of the Clean Air Act
requires that the renewable fuel be consumed in the contiguous 48
states, and any other state or territory that opts in to the program
(Hawaii has subsequently opted in). However, because renewable fuel
produced in Alaska or a U.S. territory is unlikely to be transported to
the contiguous 48 states or to Hawaii, including their renewable fuel
volumes in the calculation of the standard would not serve the purpose
intended by section 211(o) of the Clean Air Act of ensuring that the
statutorily required renewable fuel volumes are consumed in the 48
contiguous states and any state or territory that opts in.
In summary, we are proposing that the total projected non-renewable
gasoline and diesel volumes from which the annual standards are
calculated be based on EIA projections of gasoline and diesel
consumption in the contiguous 48 states and Hawaii, adjusted by
constant percentages of 11.9% and 15.2% in 2010 to account for small
refinery/refiner gasoline and diesel volumes, respectively, and with
built-in correction factors to be used when and if Alaska or a
territory opt-in to the program. If actual gasoline and diesel
consumption were to exceed the EIA projections, the result would be
that renewable fuel volumes would exceed the statutory volumes.
Conversely, if actual gasoline and diesel consumption was less than the
EIA projection for a given year, actual renewable fuel volumes could be
lower than the statutory volumes depending on market conditions.
Additional special considerations in establishing the annual cellulosic
biofuel standard are discussed below in Section III.E.1.c.
The following formulas will be used to calculate the percentage
standards:
[GRAPHIC] [TIFF OMITTED] TN26MY09.000
[GRAPHIC] [TIFF OMITTED] TN26MY09.001
[GRAPHIC] [TIFF OMITTED] TN26MY09.002
[GRAPHIC] [TIFF OMITTED] TN26MY09.003
[[Page 24955]]
Where
StdCB,i = The cellulosic biofuel standard for year i, in
percent
StdBBD,i = The biomass-based diesel standard for year i,
in percent
StdAB,i = The advanced biofuel standard for year i, in
percent
StdRF,i = The renewable fuel standard for year i, in
percent
RFVCB,i = Annual volume of cellulosic biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVBBD,i = Annual volume of biomass-based diesel required
by section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVAB,i = Annual volume of advanced biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVRF,i = Annual volume of renewable fuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
Gi = Amount of gasoline projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons*
Di = Amount of diesel projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons
RGi = Amount of renewable fuel blended into gasoline that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons
RDi = Amount of renewable fuel blended into diesel that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons
GSi = Amount of gasoline projected to be used in Alaska
or a U.S. territory in year i if the state or territory opts in, in
gallons*
RGSi = Amount of renewable fuel blended into gasoline
that is projected to be consumed in Alaska or a U.S. territory in
year i if the state or territory opts in, in gallons
DSi = Amount of diesel projected to be used in Alaska or
a U.S. territory in year i if the state or territory opts in, in
gallons*
RDSi = Amount of renewable fuel blended into diesel that
is projected to be consumed in Alaska or a U.S. territory in year i
if the state or territory opts in, in gallons
GEi = The amount of gasoline projected to be produced by
exempt small refineries and small refiners in year i, in gallons, in
any year they are exempt per Sec. Sec. 80.1441 and 80.1442,
respectively. Equivalent to 0.119 * (Gi -
RGi).
DEi = The amount of diesel projected to be produced by
exempt small refineries and small refiners in year i, in gallons, in
any year they are exempt per Sec. Sec. 80.1441 and 80.1442,
respectively. Equivalent to 0.152 * (Di -
RDi).
* Note that these terms for projected volumes of gasoline and
diesel use include gasoline and diesel that has been blended with
renewable fuel.
b. Proposed Standards for 2010
In today's NPRM we are proposing the specific standards that would
apply to all obligated parties in calendar year 2010. We will consider
comments received on these standards as part of the comment period
associated with today's NPRM, and we intend to issue a Federal Register
notice by November 30, 2009 setting the applicable standards for 2010.
While we are not proposing standards for 2011 and beyond, we present
our current projections of these standards in the next section.
Under CAA section 211(o)(7)(D)(i), EPA is required to make a
determination each year regarding whether the required volumes of
cellulosic biofuel for the following year can be produced. For any
calendar year for which the projected volume of cellulosic biofuel
production is less than the minimum required volume, the projected
volume becomes the basis for the cellulosic biofuel standard. In such a
case, the statute also indicates that EPA may also lower the required
volumes for advanced biofuel and total renewable fuel.
Based on information available to date, we believe that there are
sufficient plans underway to build plants capable of producing 0.1
billion gallons of cellulosic biofuel in 2010, the minimum volume of
cellulosic biofuel required by EISA for 2010. Our April 2009 industry
assessment concludes that there could be seven small commercial-scale
plants online in 2010 (as well as a series of pilot and demonstration
plants) capable of producing just over 100 million gallons of
cellulosic biofuel. And since the majority of this production (73%) is
projected to be cellulosic diesel, the ethanol-equivalent complaince
volume could be closer to 145 million gallons. While it is possible
that some of these plants could be delayed or a portion of the
projected production may not meet the definition of ``cellulosic
biofuel'' (due to mixed feedstocks), it is also possible that other
plans could proceed ahead of their current schedules. For more on the
2010 cellulosic biofuel production assessment, refer to Section 1.5.3.4
of the DRIA
On the basis of this information, we are not proposing that any
portion of the cellulosic biofuel requirement for 2010 be waived.
Therefore, we are proposing that the volumes shown in Table II.A.1-1 be
used as the basis for the applicable standards for 2010. As described
more fully in Section III.E.2 below, we are also proposing that the
2010 standard for biomass-based diesel be based on the combined
required volumes for 2009 and 2010, or a total of 1.15 billion gallons.
The proposed standards for 2010 are shown in Table III.E.1.b-1.
Table III.E.1.b-1--Proposed Standards for 2010
[Percent]
------------------------------------------------------------------------
------------------------------------------------------------------------
Cellulosic biofuel............................................. 0.06
Biomass-based diesel........................................... 0.71
Advanced biofuel............................................... 0.59
Renewable fuel................................................. 8.01
------------------------------------------------------------------------
As described more fully in Section III.E.1.d below, we are
proposing that the RFS2 program take effect on January 1, 2010, but we
are also taking comment on an effective date later than January 1,
2010, including January 1, 2011 and a mid-2010 effective date. If the
RFS2 program became effective mid-2010, the RFS1 program would apply
during the first part of 2010 and the RFS2 program would apply for the
remainder of the year. We request comment on whether the four proposed
standards shown in Table III.E.1.b-1 would apply only to gasoline and
diesel produced or imported after the RFS2 effective date or should
apply to all gasoline and diesel produced in 2010. We also request
comment on whether a single standard for total renewable fuel should
apply under RFS1 regulations for the first part of 2010.
c. Projected Standards for Other Years
As discussed above, we intend to set the percentage standards for
each upcoming year based on the most recent EIA projections, and using
the other sources of information as noted above. We would publish the
standard in the Federal Register by November 30 of the preceding year.
The standards would be used to determine the renewable volume
obligations based on an obligated party's total gasoline and diesel
production or import volume in a calendar year, January 1 through
December 31. An obligated party will calculate its Renewable Volume
Obligations (discussed in Section III.G.1) using the annual standards.
For illustrative purposes, we have estimated the standards for 2011
and later based on current information using the formulas discussed
above, and assuming no modifications to the annual volumes
required.\33\ These values are listed below in Table III.E.1.c-1. The
required renewable fuel volumes specified in EISA are shown in Table
II.A.1-1. The projected gasoline, diesel and renewable fuels volumes
were determined from EIA's energy projections. Variables related to
Alaska or territory opt-ins were set to zero since we do not have any
information related
[[Page 24956]]
to their participation at this time. No adjustment was made for small
refiner or small refinery volumes since their exemption is assumed to
end at the end of the 2010 compliance period.
---------------------------------------------------------------------------
\33\ ``Calculation of the Renewable Fuel Standard for Gasoline
and Diesel,'' memo to the docket from Christine Brunner, ASD, OTAQ,
EPA, April 2009.
Table III.E.1.c-1--Projected Standards Under RFS2
[percent]
----------------------------------------------------------------------------------------------------------------
Biomass-
Cellulosic based Advanced Renewable
biofuel diesel biofuel fuel
----------------------------------------------------------------------------------------------------------------
2011........................................................ 0.15 0.49 0.83 8.60
2012........................................................ 0.31 0.61 1.22 9.31
2013........................................................ 0.61 0.61a 1.68 10.09
2014........................................................ 1.07 0.61a 2.28 11.05
2015........................................................ 1.83 0.61a 3.35 12.48
2016........................................................ 2.58 0.61a 4.40 13.49
2017........................................................ 3.34 0.61a 5.46 14.56
2018........................................................ 4.25 0.61a 6.68 15.80
2019........................................................ 5.19 0.61a 7.95 17.11
2020........................................................ 6.47 0.62a 9.25 18.50
2021........................................................ 8.40 0.62a 11.21 20.54
2022........................................................ 10.07 0.63a 13.21 22.65
----------------------------------------------------------------------------------------------------------------
\a\ These projected standards represent the minimum volume of 1.0 billion gallons required by EISA. The actual
volume used to set the standard would be determined by EPA through a future rulemaking.
d. Alternative Effective Date
Although we are proposing that the RFS2 regulatory program begin on
January 1, 2010 which, depending on timing for the final rule, would
allow approximately two months from the anticipated issuance of the
rule to its implementation, we seek comment on whether an effective
date later than January 1, 2010 would be necessary. If the RFS2 program
was not made effective on January 1, 2010, the most straightforward
alternative start date would be January 1, 2011. Delaying to 2011 would
provide regulated parties additional lead time and would allow all the
new requirements and standards to go into effect at the beginning of an
annual compliance period. However, delaying to 2011 would also mean
that demonstrating compliance with the separate requirements for
biomass-based diesel, cellulosic biofuel, and advanced biofuel mandates
would not go into effect until 2011. The total renewable fuel mandate
in EISA may be able to be implemented with the RFS1 regulations until
such time as the RFS2 regulations become effective. However, under the
RFS1 regulations, this entire standard would be for conventional
biofuels and would be applied to gasoline producers and importers only.
There would be no obligation with respect to diesel fuel producers and
importers, resulting in a numerically larger standard that would apply
to gasoline producers only and which could compel them to market a
larger proportion of ethanol as E85 to acquire sufficient RINs for
compliance. One possible way to address this issue would be to reduce
the 2010 total renewable fuel standard proportionately to reflect the
application of the standard only to gasoline producers. However, it
does not appear that EPA has statutory authority, or discretion under
the RFS1 regulations, to modify the total renewable fuel mandate in
this manner. As discussed below in Section III.E.2, any delay beyond
January 1, 2010 also has implications for our proposed treatment of the
biomass-based diesel volumes required for 2009. EPA invites comment on
whether RFS2 implementation should be delayed to January 1, 2011 and,
if so, the manner in which the EISA-mandated RFS program should be
implemented prior to that date.
Another alternative would be to delay the effective date of the
RFS2 program to some time after January 1, 2010 but before January 1,
2011. This alternative would raise the same issues described above
(regarding the option of a delay until January 1, 2011) for that
portion of 2010 during which RFS2 was not effective. It would also
raise additional transition and implementation issues. For instance, we
would need to determine whether diesel fuel producers and importers
carry a total renewable fuel obligation calculated on the basis of
their production for all of 2010 or just the production period in 2010
during which the RFS2 regulations are effective. We would also need to
determine whether the 2010 cellulosic biofuel, biomass-based diesel,
and advanced biofuel standards applicable under RFS2 should apply to
production of gasoline and diesel for all of 2010 or just the
production that occurred after the RFS2 regulations were effective If
the latter, EPA would need to determine the extent to which RFS1 RINs
generated in the first part of 2010 could be used to satisfy RFS2
obligations, given that some 2010 RINs would be generated under the
RFS1 requirements while other 2010 RINs would be generated under RFS2
requirements. To accomplish this, RINs generated under the RFS2
requirements would need to be distinguished from RINs generated under
RFS1 requirements through the RINs' D codes. Section III.A provides a
more detailed description of this alternative approach to the
assignment of D codes under the RFS2 program. For additional discussion
of how RFS1 RINs would be treated in the transition to the RFS2
program, see our proposed transition approach described in Section
III.G.3.
We are requesting comment on all issues related to the option of an
RFS2 start date sometime after January 1, 2010, including the need for
such a delayed start, the level of the standards, treatment of diesel
producers and importers, whether the standards for advanced biofuel,
cellulosic biofuel and biomass-based diesel should apply to the entire
2010 production or just the production that would occur after the RFS2
effective date, treatment of the 2009 and/or 2010 biomass-based diesel
standard, and the extent to which RFS1 RINs should be valid to show
compliance with RFS2 standards.
2. Treatment of Biomass-Based Diesel in 2009 and 2010
We are proposing to make the RFS2 program required through EISA
effective on January 1, 2010. The RFS2 program would include an
expansion to four
[[Page 24957]]
separate standards, changes to the RIN system, changes to renewable
fuel definitions, the introduction of lifecycle GHG reduction
thresholds, and the expansion of obligated parties to include producers
and importers of diesel and nonroad fuel. However, EISA requires
promulgation of the final RFS2 regulations within one year of enactment
and presumes full implementation by January 1, 2009. Moreover, EISA
specifies new volume requirements for biomass-based diesel, advanced
biofuel, and total renewable fuel for 2009. As described in Section
II.A.5, it is not possible to have the full RFS2 program implemented by
January 1, 2009. As a result, we must consider how to treat these
separate volume requirements for 2009.
a. Proposed Shift in Biomass-Based Diesel Requirement From 2009 to 2010
The statutory language in EISA does not indicate that the existing
RFS1 regulations cease to apply on January 1, 2009. Rather, it directs
us to ``revise the regulations'' to ensure that the required volumes of
renewable fuel are contained in transportation fuel. As a result, until
the RFS1 regulations are changed through a notice and comment
rulemaking process, they will remain in effect. If the full RFS2
program goes into effect on January 1, 2010, then the existing RFS1
regulations will continue to apply in 2009.
Under RFS1, we set the applicable standard each November for the
following compliance period using the required volume of renewable fuel
specified in the Clean Air Act, gasoline volume projections from EIA,
and the formula provided in the regulations at Sec. 80.1105(d). Since
final RFS2 regulations will not be promulgated by the end of 2008, this
RFS1 standard-setting process will apply to the 2009 compliance period
as well. However, EISA modifies the Clean Air Act to increase the
required volume of total renewable fuel for 2009 from 6.1 to 11.1
billion gallons, and thus the applicable standard for 2009, published
in November of 2008,\34\ reflects this higher volume. This will ensure
that the total renewable fuel requirement under EISA for 2009 is
implemented.
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\34\ See 73 FR 70643.
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While the total renewable fuel volume of 11.1 billion gallons will
be required in 2009, the existing RFS1 regulations do not provide a
mechanism for requiring the 0.5 billion gallons of biomass-based diesel
or the 0.6 billion gallons of advanced biofuel required by EISA for
2009. Below we describe our proposed approach for biomass-based diesel.
With regard to advanced biofuel, we believe that it is not necessary to
implement a separate requirement for the 0.6 billion gallons. Due to
the nested nature of the volume requirements, the 0.5 billion gallon
requirement for biomass-based diesel would count towards meeting the
advanced biofuel requirement, leaving just 0.1 billion gallons that we
believe will be supplied through imports of sugar-based ethanol even
without a specific mandate for advanced biofuel.
We believe that the deficit carryover provision provides a
conceptual mechanism for ensuring that the volume of biomass-based
diesel that is required by EISA for 2009 is actually consumed. As
described in the RFS1 final rule, the statute permits obligated parties
to carry a deficit of any size from one compliance period to the next,
so long as a deficit is not carried over two years in a row.\35\ In
theory this would allow any and all obligated parties to defer
compliance with any or all of the 2009 standards until 2010. Based on
the precedent set by this statutory provision, we propose that the
compliance demonstration for the 2009 biomass-based diesel requirement
be extended to 2010. We believe this approach would provide a
reasonable transition for biomass-based diesel, given our inability to
issue regulations before the beginning of the 2009 calendar year. Our
proposed approach would implement the 2009 and 2010 biomass-based
diesel volume requirements in a way that ensures that these two years
worth of biomass-based diesel would be used, while providing reasonable
lead time for obligated parties. It would avoid a transition that fails
to have any requirements related to the 2009 biomass-based diesel
volume, and instead would require the use of the 2009 volume but would
achieve this by extending the compliance period by one year. We believe
this is a reasonable exercise of our authority under section 211(o)(2)
to issue regulations that ensure that the volumes for 2009 are
ultimately used, even though we are unable to issue final regulations
prior to the 2009 compliance year. In addition, it is a practical
approach that provides obligated parties with appropriate lead time.
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\35\ See 72 FR 23935.
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To implement our proposed approach, the 2009 requirement of 0.5
billion gallons of biomass-based diesel would be combined with the 2010
requirement of 0.65 billion gallons for a total adjusted 2010
requirement of 1.15 billion gallons of biomass-based diesel. The net
effect is that obligated parties can demonstrate compliance with both
the 2009 and 2010 biomass-based diesel requirements in 2010, consistent
with what the deficit carryover provision would have allowed had we
been able to implement the full RFS2 program by January 1, 2009.
Furthermore, we propose to allow all 2009 biodiesel and renewable
diesel RINs, identifiable through an RR code of 15 or 17 respectively,
to be valid for showing compliance with the adjusted 2010 biomass-based
diesel standard of 1.15 billion gallons. This use of previous year RINs
for current year compliance would be consistent with our approach to
any other standard for any other year and consistent with the
flexibility available to any obligated party that carried a deficit
from one year to the next. Moreover, it allows an obligated party to
acquire sufficient biodiesel and renewable diesel RINs during 2009 to
comply with the 0.5 billion gallons requirement, even though their
compliance demonstration would not occur until the 2010 compliance
period.
While we recognize that RINs generated in 2009 under RFS1
regulations will differ from those generated in 2010 under RFS2
regulations in terms of the purpose of the D code and the other
criteria for establishing the eligibility of renewable fuel, we believe
that the use of 2009 RINs for compliance with the 2010 adjusted
standard is appropriate. It is also consistent with CAA section
211(o)(5), which provides that validly generated credits may be used to
show compliance for 12 months. The program transition issue of RINs
generated under RFS1 but used to meet standards under RFS2 is discussed
in more detail in Section III.G.3 below.
Rather than reducing the 2009 volume requirement for total
renewable fuel by 0.5 billion gallons of biomass-based diesel and
increasing the 2010 volume requirements for advanced biofuel and total
renewable fuel by the same amount, we are proposing that the only
standard that would be adjusted would be that for biomass-based diesel
in 2010. This approach would minimize the changes to the annual RFS
volume requirements and thus would more directly implement the
requirements of the statute. However, this approach would also require
that we allow 2009 biodiesel and renewable diesel RINs to be used for
compliance purposes for both the 2009 total renewable fuel standard as
well as the 2010 adjusted biomass-based diesel standard, but not for
the 2010 advanced biofuel or total renewable fuel standards. We have
[[Page 24958]]
identified two possible options for accomplishing this.
i. First Option for Treatment of 2009 Biodiesel and Renewable Diesel
RINs
In the first option, an obligated party would add up the 2009
biodiesel and renewable diesel RINs that he used for 2009 compliance
with the RFS1 standard for renewable fuel, and reduce his 2010 biomass-
based diesel obligation by this amount. Any remaining 2010 biomass-
based diesel obligation would need to be covered with either 2009
biodiesel and renewable diesel RINs that were not used for compliance
with the renewable fuel standard in 2009, or 2010 biomass-based diesel
RINs. This is the option we are proposing in today's notice.
The primary drawback of our proposed option is that 2009 biodiesel
and renewable diesel RINs used to demonstrate compliance with the 2009
renewable fuel standard could not be traded to any other party for use
in complying with the 2010 biomass-based diesel standard. Thus, for
instance, if a refiner acquired many 2009 biodiesel and renewable
diesel RINs and used them for compliance with the 2009 renewable fuel
standard, and if the number of these 2009 RINs was more than he needed
to comply with his 2010 biomass-based diesel obligation, he could not
trade the excess to another party. These excess RINs could never be
applied to the adjusted 2010 biomass-based diesel standard by any
party, and as a result the actual demand for biomass-based diesel could
exceed 1.15 bill gal. We believe that obligated parties could avoid
this outcome by planning ahead to use no more 2009 biodiesel and
renewable diesel RINs for 2009 compliance with the renewable fuel
standard than they would need for 2010 compliance with the adjusted
biomass-based diesel standard. Moreover, this option could provide
obligated parties with sufficient incentive to collect 0.5 billion
gallons worth of biodiesel and renewable diesel RINs in 2009 without
significant changes to the program's requirements.
ii. Second Option for Treatment of 2009 Biodiesel and Renewable Diesel
RINs
Under the second option, biodiesel and renewable diesel RINs
generated in 2009 would be allowed to be used for compliance purposes
in both 2009 and 2010. To enable this option, for the specific and
limited case of biodiesel and renewable diesel RINs generated in 2009,
we would modify the regulatory prohibition at Sec. 80.1127(a)(3)
limiting the use of RINs for compliance demonstrations to a single
compliance year to allow 2009 biodiesel and renewable diesel RINs to be
used for compliance purposes in two different years. This change would
allow all 2009 biodiesel and renewable diesel RINs to be used to meet
the adjusted biomass-based diesel standard in 2010 regardless of
whether they were also used to meet the total renewable fuel standard
in 2009. We would also need to lift the 20% rollover cap that would
otherwise limit the use of 2009 RINs in 2010, and instead allow any
number of 2009 biodiesel and renewable diesel RINs to be used to meet
the 2010 biomass-based diesel standard.
This option would also require that we implement additional RIN
tracking procedures. Under the current RFS1 regulations, RINs used for
compliance demonstrations are removed from the RIN market, while under
this alternative approach biodiesel and renewable diesel RINs could
continue to be valid for compliance purposes vis a vis the adjusted
2010 biomass-based diesel standard even if they were already used for
compliance with the renewable fuel standard in 2009. The regulations
would need to be changed to allow this, and both EPA's and industry's
IT systems would need to be modified to allow for this temporary
change.
Due to the additional complexities associated with this option, we
are not proposing it. Nevertheless, we request comment on it, as it
would more explicitly reflect two separate obligations for calendar
year 2009: An RFS1 obligation for total renewable fuel, and an
obligation for biomass-based diesel that starts during 2009 with
compliance required by the end of 2010 for a volume that covers both
2009 and 2010. We also request comment on whether under this option we
should allow 2009 biodiesel and renewable diesel RINs to continue to be
bought and sold after 2009 if they are used to demonstrate compliance
with the 2009 total renewable fuel standard.
b. Proposed Treatment of Deficit Carryovers and Valid RIN Life For
Adjusted 2010 Biomass-Based Diesel Requirement
Although our proposed transition approach is conceptually similar
to the statutory deficit carryover provision, the regulatory
requirements would not explicitly treat the movement of the 0.5 billion
gallons biomass-based diesel requirement from 2009 to 2010 as a deficit
carryover. In the absence of any modifications to the deficit carryover
provisions, then, an obligated party that did not fully comply with the
2010 biomass-based diesel requirement of 1.15 billion gallons could
carry a deficit of any amount into 2011.
If we had been able to implement the 2009 biomass-based diesel
volume requirement of 0.5 billion gallons in calendar year 2009, the
2010 biomass-based diesel standard would have been based on 0.65
billion gallons. In this case, the maximum volume of biomass-based
diesel that could have been carried into 2011 as a deficit would have
been 0.65 billion gallons. In the context of our proposed approach to
the treatment of biomass-based diesel in 2009 and 2010, we believe that
it would be inappropriate to allow the full 1.15 billion gallons to be
carried into 2011 as a deficit. Therefore, we are proposing that
obligated parties be prohibited from carrying over a deficit into 2011
larger than 0.65 bill gal. In practice, this would mean that deficit
carryovers from 2010 into 2011 for biomass-based diesel could not
exceed 57% of an obligated party's 2010 RVO.
Similarly, the combination of the 0.5 billion gallons biomass-based
diesel requirement from 2009 with the 2010 volume raises the question
of whether 2008 biodiesel or renewable diesel RINs could be used for
compliance in 2010 with the adjusted biomass-based diesel standard.
Without a change to the regulations, this practice would not be allowed
because RINs are only valid for compliances purposes for the year
generated or the year after. However, if we had been able to implement
the full RFS2 program for the 2009 compliance year, 2008 biodiesel and
renewable diesel RINs would be valid for compliance with the 0.5
billion gallons biomass-based diesel requirement. Therefore, we are
proposing to modify the regulations to allow excess 2008 biodiesel and
renewable diesel RINs to be used for compliance purposes in 2009 or
2010. We request comment on this proposal.
We also propose that the 20% rollover cap would continue to apply
in all years as described in more detail in Section IV.D. However, we
are proposing an additional constraint in the application of this cap
to the biomass-based diesel obligation in the 2010 compliance year. If
the 2009 biomass-based diesel volume requirement of 0.5 billion gallons
could have been required in 2009, the use of excess 2008 biodiesel and
renewable diesel RINs would have been limited to 20% of the 2009
requirement, or a maximum of 0.1 billion gallons. Since we are
proposing to require that the 2009 and 2010 biomass-based diesel
requirements be combined for a total of 1.15 billion gallons, we
propose that the maximum allowable portion that could be derived from
2008 biomass-based
[[Page 24959]]
diesel RINs would be 0.1 billion gallons. This would represent 8.7% of
the 2010 obligation (\0.1/1.15\). In addition to this limit on the use
of 2008 RINs for 2010 compliance that is unique to this option, the 20%
rollover cap would continue to apply to the use of all previous-year
RINs used for compliance purposes in 2010. Thus, the total number of
all 2008 and 2009 RINs that could be used to meet the 2010 biomass-
based diesel obligation would continue to be capped at 20%. We request
comment on this approach.
Finally, we are proposing to allow 2009 RINs that are retired
because they are ultimately used for nonroad or home heating oil
purposes to be valid for compliance with the 2010 RFS standard.
Currently, under RFS1, RINs associated with renewable fuel that is not
ultimately used as motor vehicle fuel must be retired. In contrast,
under EISA, renewable fuel used for nonroad purposes, except for use in
industrial boilers or ocean-going vessels, is considered transportation
fuel, and is eligible for the RFS program. We are proposing that 2009
RINs generated for renewable fuel that is ultimately used for nonroad
or home heating oil purposes continue to be retired by the appropriate
party pursuant to 80.1129(e). However, we are proposing that those
retired 2009 nonroad or home heating oil RINs be eligible for
reinstatement by the retiring party in 2010. These reinstated RINs may
be used by that party to demonstrate compliance with a 2010 RVO, or for
sale to other parties who would then use the RINs for compliance
purposes. While we anticipate that this proposed provision would be
utilized largely for biodiesel RINs that were retired by parties that
sold them for use as nonroad fuel or home heating oil, we propose that
the provision apply to all RINs. We request comment on this proposed
approach.
c. Alternative Approach to Treatment of Biomass-Based Diesel in 2009
and 2010
Under our proposed approach, the 0.5 billion gallon requirement for
biomass-based diesel in 2009 would be added to the 0.65 billion gallon
requirement for 2010, and the total volume of 1.15 billion gallons
would be used as the basis of a single adjusted standard applicable to
obligated parties in 2010. The compliance demonstration for this single
standard would need to be made by February 28, 2011. As an alternative,
we could establish two separate biomass-based diesel standards for
which compliance must be demonstrated by February 28, 2011. One of
these standards would be based on 0.65 billion gallons and would
represent the applicable biomass-based diesel standard for 2010. The
other standard would be based on 0.5 billion gallons and would
represent the applicable biomass-based diesel standard for 2009. In
essence, the standard based on 0.5 billion gallons would be for the
2009 calendar year even though we would extend its compliance
demonstration until February 28, 2011.
In this alternative, only excess 2008 or 2009 biodiesel and
renewable diesel RINs could be used to comply with the standard based
on 0.5 billion gallons. Excess 2009 biodiesel or renewable diesel RINs
and 2010 biomass-based diesel RINs could be used to comply with the
standard based on 0.65 billion gallons. The 20% rollover cap would
apply to both standards. As a result, this alternative approach would
effectively implement the 2009 biomass-based diesel standard in
calendar year 2009, and thus it may come closer to the statute's
requirements than our proposed approach. Moreover, the existing
provisions for the valid life of RINs and deficit carryover would not
need modification as they would under our proposed approach.
However, this alternative would arguably provide less than
appropriate lead time for meeting the 0.5 billion gallon obligation, as
it would require obligated parties to begin acquiring sufficient 2008
and 2009 biodiesel and renewable diesel RINs starting in January of
2009 even though our final rulemaking is not expected to be issued
until the fall of 2009. There are two reasons that this lead time might
nevertheless be considered appropriate. First, obligated parties could
wait until the final rule is published to begin acquiring 2008 and 2009
biodiesel and renewable diesel RINs. Moreover, they would not need to
demonstrate compliance with the 0.5 billion gallons standard until
February 28, 2011, providing ample time to locate and acquire
sufficient RINs. Second, the deficit carryover provisions would allow
obligated parties to treat the separate 0.5 and 0.65 billion gallon
requirements as a single requirement that must be met in total by
February 28, 2011. In this sense, this alternative is similar to our
proposed approach. We request comment on this alternative approach.
d. Treatment of Biomass-Based Diesel Under an RFS2 Effective Date Other
Than January 1, 2010
The above discussion assumes that the RFS2 program is effective on
January 1, 2010. If the program effective date is delayed, similar
issues arise regarding whether EISA volume mandates for fuel categories
with no mandates under RFS1 are lost, or should be recaptured through a
delayed compliance demonstration in the first year of the RFS2 program.
For a delay beyond January 1, 2010, the issues relate to cellulosic
biofuel and advanced biofuel in addition to biomass-based diesel.
For instance, our proposed approach to biomass-based diesel
effectively makes the one-year deficit carryover a necessary element of
compliance for 2010, and maintains the two-year valid life of RINs.
However, if the effective date of RFS2 were delayed to January 1, 2011,
we could not take the same approach. By requiring compliance
demonstrations to be made in 2011 for the required biomass-based diesel
volumes mandated for 2009, 2010, and 2011, we would be effectively
requiring a 2-year deficit carryover and a three-year valid life of
RINs, contrary to the statutory limitations. As an alternative, one
possible approach would be to only sum the required biomass-based
diesel volumes for 2010 and 2011 and require compliance demonstrations
at the end of 2011.
If the RFS2 program became effective in mid-2010, we would also
need to determine the appropriate level of the biomass-based diesel
standard, and whether it would apply to gasoline and diesel volumes
produced only after the RFS2 effective date, or all gasoline and diesel
volumes produced in 2010.
EPA invites comment on whether and how it should recapture these
volume mandates under different start-date scenarios.
F. Fuels That Are Subject to the Standards
Under RFS1, producers and importers of gasoline are obligated
parties subject to the standards. Any party that produces or imports
only diesel fuel is not subject to the standards. EISA changes this
provision by expanding the RFS program in general to include
transportation fuel. As discussed above, however, section 211(o)(3)
continues to require EPA to determine which refiners, blenders, and
importers are treated as subject to the standard. As described further
in Section III.G below, we are proposing that the sum of all highway
and nonroad gasoline and diesel fuel produced or imported within a
calendar year be the basis on which the RVOs are calculated. This
section provides our proposed definition of gasoline and diesel for the
purposes of the RFS program.
[[Page 24960]]
1. Gasoline
As with the RFS1 program, the volume of gasoline used in
calculating the RVO under RFS2 would continue to include all finished
gasoline (reformulated gasoline (RFG) and conventional gasoline (CG))
produced or imported for use in the contiguous United States or Hawaii,
as well as all unfinished gasoline that becomes finished gasoline upon
the addition of oxygenate blended downstream from the refinery or
importer. This would include both unfinished reformulated gasoline,
called ``reformulated gasoline blendstock for oxygenate blending,'' or
``RBOB,'' and unfinished conventional gasoline designed for downstream
oxygenate blending (e.g., sub-octane conventional gasoline), called
``CBOB.'' The volume of any other unfinished gasoline or blendstock,
such as butane or naphtha produced in a refinery, would not be included
in the obligated volume, except where the blendstock is combined with
other blendstock or gasoline to produce finished gasoline, RBOB, or
CBOB. Where a blendstock is blended with other blendstock to produce
finished gasoline, RBOB, or CBOB, the total volume of the gasoline
blend would be included in the volume used to determine the blender's
renewable fuels obligation. Where a blendstock is added to finished
gasoline, only the volume of the blendstock would be included, since
the finished gasoline would have been included in the compliance
determinations of the refiner or importer of the gasoline. For purposes
of this preamble, the various gasoline products described above that we
are proposing to include in a party's obligated volume would
collectively be called ``gasoline.''
Also consistent with the RFS1 program, we propose to continue to
exclude any volume of renewable fuel contained in gasoline from the
volume of gasoline used to determine the renewable fuels obligations.
This exclusion would apply to any renewable fuels that are blended into
gasoline at a refinery, contained in imported gasoline, or added at a
downstream location. Thus, for example, any ethanol added to RBOB or
CBOB at a refinery's rack or terminal downstream from the refinery or
importer would be excluded from the volume of gasoline used by the
refiner or importer to determine the obligation. This is consistent
with how the standard itself is calculated--EPA determines the
applicable percentage by comparing the overall projected volume of
gasoline used to the overall renewable fuel volume that is specified in
EPAct, and EPA excludes ethanol and other renewable fuels that blended
into the gasoline in determining the overall projected volume of
gasoline. When an obligated party determines their RVO by applying the
applicable percentage to the amount of gasoline they produce or import,
it is consistent to also exclude ethanol and other renewable fuel
blends from the calculation of the volume of gasoline produced.
As with the RFS1 program, we are proposing that Gasoline Treated as
Blendstock (GTAB) would continue to be treated as a blendstock under
the RFS2 program, and thus would not count towards a party's renewable
fuel obligation. Where the GTAB is blended with other blendstock (other
than renewable fuel) to produce gasoline, the total volume of the
gasoline blend, including the GTAB, would be included in the volume of
gasoline used to determine the renewable fuel obligation. Where GTAB is
blended with renewable fuel to produce gasoline, only the GTAB volume
would be included in the volume of gasoline used to determine the
renewable fuel obligation. Where the GTAB is blended with finished
gasoline, only the GTAB volume would be included in the volume of
gasoline used to determine the renewable fuel obligation.
2. Diesel
As discussed above in Section II.A.4, EISA expanded the RFS program
to include transportation fuels other than gasoline, and we are
proposing that both highway and nonroad diesel be used in calculating a
party's RVO. We are proposing that any party that produces or imports
petroleum-based diesel fuel that is designated as motor vehicle,
nonroad, locomotive, and marine diesel fuel (MVNRLM) (or any
subcategory of MVNRLM) would be required to include the volume of that
diesel fuel in the determination of its RVO under the RFS2 rule. We are
proposing that diesel fuel would include any distillate fuel that meets
the definition of MVNRLM diesel fuel as it has already been defined in
the regulations at Sec. 80.2(qqq), including any subcategories such as
MV (motor vehicle diesel produced for use in highway diesel engines and
vehicles), NRLM (diesel produced for use in nonroad, locomotive, and
marine diesel engines and equipment/vessels), NR (diesel produced for
use in nonroad engines and equipment), and LM (diesel produced for use
in locomotives and marine diesel engines and vessels).\36\ We are
proposing that transportation fuels meeting the definition of MVNRLM
would be used to calculate the RVOs, and refiners, blenders, or
importers of MVNRLM would be treated as obligated parties. As such,
diesel fuel that is designated as heating oil, jet fuel, or any
designation other than MVNRLM or a subcategory of MVNRLM, would not be
subject to the applicable percentage standard and would not be used to
calculate the RVOs.\37\
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\36\ EPA's diesel fuel regulations use the term ``nonroad'' to
designate one large category of land-based off-highway engines and
vehicles, recognizing that locomotive and marine engines and vessels
are also nonroad engines and vehicles under EPAct's definition of
nonroad. Except where noted, the discussion of nonroad in reference
to transportation fuel includes the entire category covered by
EPAct's definition of nonroad.
\37\ See 40 CFR 80.598(a) for the kinds of fuel types used by
refiners or importers in designating their diesel fuel.
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We are also requesting comment on the idea that any diesel fuel not
meeting these requirements, such as distillate or residual fuel
intended solely for use in ocean-going vessels, would not be used to
calculate the RVOs. As discussed above in Section II.A.4, EISA
specifies that ``transportation fuels'' do not include fuels for use in
ocean-going vessels. We are interpreting the term ``ocean-going
vessel'' to mean those vessels that are powered by Category 3 (C3)
marine engines and that use residual fuel or operate internationally;
we request comment on this interpretation. As such, we are requesting
comment on the concept that fuel intended solely for use in ocean-going
vessels, or that an obligated party can verify as having been used in
an ocean-going vessel, would be excluded from the renewable fuel
standards. Further, we are also requesting comment on whether fuel used
on such vessels with C2 engines should also be excluded from the
renewable fuel standards, and how such an exemption should be phrased.
3. Other Transportation Fuels
As discussed further in Section III.J.3, below, we propose that
transportation fuels other than gasoline or MVNRLM diesel fuel (natural
gas, propane, and electricity) would not be used to calculate the RVOs
of any obligated party. We believe this is a reasonable way to
implement the obligations of 211(o)(3) because the volumes are small
and the producers cannot readily differentiate the small transport
portion from the large non-transport portion (in fact, the producer may
have no knowledge of its use in transport); we will reconsider this
approach if and when these volumes grow. At the same time, it is clear
that other fuels can meet the definition of ``transportation fuel,''
and we are proposing that under certain
[[Page 24961]]
circumstances, producers or generators of such other transportation
fuels may generate RINs as a producer or importer of a renewable fuel.
See Section III.B.1.a for further discussion of other RIN-generating
fuels.
G. Renewable Volume Obligations (RVOs)
Under the current RFS program, each obligated party must determine
its RVO based on the applicable percentage standard and its annual
gasoline volume. The RVO represents the volume of renewable fuel that
the obligated party must ensure is used in the U.S. in a given calendar
year. Obligated parties must meet their RVO through the accumulation of
RINs which represent the amount of renewable fuel used as motor vehicle
fuel that is sold or introduced into commerce within the U.S. Each
gallon-RIN would count as one gallon of renewable fuel for compliance
purposes.
We propose to maintain this approach to compliance under the RFS2
program. One primary difference between the current and new RFS
programs in terms of demonstrating compliance would be that each
obligated party would now have four RVOs instead of one (through 2012)
or two (starting in 2013) under the RFS1 program. Also, as discussed
above, RVOs would be calculated based on production or importation of
both gasoline and diesel fuels, rather than gasoline alone.
By acquiring RINs and applying them to their RVOs, obligated
parties are effectively causing the renewable fuel represented by the
RINs to be consumed as transportation fuel in highway or nonroad
vehicles or engines. Obligated parties would not be required to
physically blend the renewable fuel into gasoline or diesel fuel
themselves. The accumulation of RINs would continue to be the means
through which each obligated party shows compliance with its RVOs and
thus with the renewable fuel standards.
If an obligated party acquires more RINs than it needs to meet its
RVOs, then in general it could retain the excess RINs for use in
complying with its RVOs in the following year or transfer the excess
RINs to another party. If, alternatively, an obligated party has not
acquired sufficient RINs to meet its RVOs, then under certain
conditions it could carry a deficit into the next year.
This section describes our proposed approach to the calculation of
RVOs under RFS2 and the RINs that would be valid for demonstrating
compliance with those RVOs. This includes a description of the special
treatment that must be applied to 2009 RINs used for compliance
purposes in 2010, since RINs generated in 2009 under RFS1 would not be
exactly the same as those generated in 2010 under RFS2. We also
describe an alternative approach to the identification of obligated
parties that would place the obligations under RFS2 on only finished
gasoline and diesel rather than on certain blendstocks and unfinished
fuels as well. The implication of this would be that the final blender
of the gasoline or diesel would be the obligated parties rather than
producers of blendstocks and unfinished fuels.
1. Determination of RVOs Corresponding to the Four Standards
In order for an obligated party to demonstrate compliance, the
percentage standards described in Section III.E.1 which are applicable
to all obligated parties must be converted into the volumes of
renewable fuel each obligated party is required to satisfy. These
volumes of renewable fuel are the volumes for which the obligated party
is responsible under the RFS program, and are referred to here as its
RVO. Under RFS2, each obligated party would need to acquire sufficient
RINs each year to meet each of the four RVOs corresponding to the four
renewable fuel standards.
The calculation of the RVOs under RFS2 would follow the same format
as the existing formulas in the regulations at Sec. 80.1107(a), with
one modification. The standards for a particular compliance year would
be multiplied by the sum of the gasoline and diesel volume produced or
imported by an obligated party in that year rather than only the
gasoline volume as under the current program.\38\ To the degree that an
obligated party did not demonstrate full compliance with its RVOs for
the previous year, the shortfall would be included as a deficit
carryover in the calculation. CAA section 211(o)(5) only permits a
deficit carryover from one year to the next if the obligated party
achieves full compliance with its RVO including the deficit carryover
in the second year. Thus deficit carryovers could not occur two years
in succession for any of the four standards. They could, however, occur
as frequently as every other year for a given obligated party.
---------------------------------------------------------------------------
\38\ As discussed above, the diesel fuel that is used to
calculate the RVO is any diesel designated as MVNRLM or a
subcategory of MVNRLM.
---------------------------------------------------------------------------
Note that a party that produces only diesel fuel would have an
obligation for all four standards even though he would not have the
opportunity to blend ethanol into his own gasoline. Likewise, a party
that produces only gasoline will have an obligation for all four
standards even though he would not have an opportunity to blend
biomass-based diesel into his own diesel fuel. Although these
circumstances might imply that the four standards should be further
subdivided into gasoline-specific and diesel-specific standards, we do
not believe that this would be appropriate as described in Section
III.E.1. Instead, since the obligations are met through the use of
RINs, compliance with the standards does not require an obligated party
to blend renewable fuel into their own or anyone else's gasoline or
diesel fuel.
2. RINs Eligible To Meet Each RVO
Under RFS1, all RINs had the same compliance value and thus it did
not matter what the RR or D code was for a given RIN when using that
RIN to meet the total renewable fuel standard. In contrast, under RFS2
only RINs with specified D codes could be used to meet each of the four
standards.
As described in Section II.A.1, the volume requirements in EISA are
generally nested within one another, so that the advanced biofuel
requirement includes fuel that meets either the cellulosic biofuel or
the biomass-based diesel requirements, and the total renewable fuel
requirement includes fuel that meets the advanced biofuel requirement.
As a result, the RINs that can be used to meet the four standards are
likewise nested. Using the proposed D codes defined in Table III.A-1,
the RINs that could be used to meet each of the four standards are
shown in Table III.G.2-1.
Table III.G.2-1--RINs That Can Be Used To Meet Each Standard
----------------------------------------------------------------------------------------------------------------
Standard Obligation Allowable D codes
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.................... RVOCB.............................. 1.
[[Page 24962]]
Biomass-based diesel.................. RVOBBD............................. 2.
Advanced biofuel...................... RVOAB.............................. 1, 2, and 3.
Renewable fuel........................ RVORF.............................. 1, 2, 3, and 4.
----------------------------------------------------------------------------------------------------------------
The nested nature of the four standards also means that we must
allow the same RIN to be used to meet more than one standard in the
same year. Thus, for instance, a RIN with a D code of 1 could be used
to meet three of the four standards, while a RIN with a D code of 3
could be used to meet both the advanced biofuel and total renewable
fuel standards. However, we propose continuing to prohibit the use of a
single RIN for compliance purposes in more than one year or by more
than one party.\39\
---------------------------------------------------------------------------
\39\ Note that we are proposing an exception to this general
prohibition for the specific and limited case of excess 2008 and
2009 biodiesel and renewable diesel RINs used to demonstrate
compliance with both the 2009 total renewable fuel standard and the
2010 biomass-based diesel standard. See Section III.E.2.a.
---------------------------------------------------------------------------
3. Treatment of RFS1 RINs Under RFS2
As described in Section II.A, we are proposing a number of changes
to the RFS program as a result of the requirements in EISA. These
changes would go into effect on January 1, 2010 and, among other
things, would affect the conditions under which RINs are generated and
their applicability to each of the four standards. As a result, RINs
generated in 2010 under RFS2 will not be exactly the same as RINs
generated in 2009 under RFS1. Given the valid RIN life that allows a
RIN to be used in the year generated or the year after, we must address
circumstances in which excess 2009 RINs are used for compliance
purposes in 2010. We must also address deficit carryovers from 2009 to
2010, since the total renewable fuel standards in these two years will
be defined differently.
a. Use of 2009 RINs in 2010
In 2009, the RFS1 regulations will continue to apply and thus
producers will not be required to demonstrate that their renewable fuel
is made from renewable biomass as defined by EISA, nor that their
combination of fuel type, feedstock, and process meets the GHG
thresholds specified in EISA. Moreover, there is no practical way to
determine after the fact if RINs generated in 2009 meet any of these
criteria. However, we believe that the vast majority of RINs generated
in 2009 would in fact meet the RFS2 requirements. First, while ethanol
made from corn must meet a 20% GHG threshold under RFS2 if produced by
a facility that commenced construction after December 19, 2007,
facilities that were already built or had commenced construction as of
December 19, 2007 are exempt from this requirement. Essentially all
ethanol produced in 2009 will meet the prerequisites for this
exemption. Second, it is unlikely that renewable fuels produced in 2009
will have been made from feedstocks grown on agricultural land that had
not been cleared or cultivated prior to December 19, 2007. In the
intervening time period, it is much more likely that the additional
feedstocks needed for renewable fuel production would come from
existing cropland or cropland that has lain fallow for some time.
Finally, the text of section 211(o)(5) states that a ``credit generated
under this paragraph shall be valid to show compliance for the 12
months as of the date of generation,'' and EISA did not change this
provision and did not specify any particular transition protocol to
follow. A straightforward interpretation of this provision is to allow
2009 RINs to be valid to show compliance for 2010 obligations.
Since there will be separate standards for cellulosic biofuel and
biomass-based diesel in 2010, RINs generated in 2009 that could be used
to meet either of these two 2010 standards should meet the GHG
thresholds of 60% and 50%, respectively. While we will not have a
mechanism in place to determine if these thresholds have been met for
RINs generated in 2009, and there are indications from our assessment
of lifecycle GHG performance that at least some renewable fuels
produced in 2009 would not meet these thresholds, nevertheless any
shortfall in GHG performance for this one transition year is unlikely
to have a significant impact on long-term GHG benefits of the program.
Based on our belief that it is critical to the smooth operation of the
program that excess 2009 RINs be allowed to be used for compliance
purposes in 2010, we are proposing that RINs generated in 2009 to
represent cellulosic biomass ethanol whose GHG performance has not been
verified would still be valid for use for 2010 compliance purposes for
the cellulosic biofuel standard. Likewise, we are proposing that RINs
generated in 2009 to represent biodiesel and renewable diesel whose GHG
performance has not been verified would still be valid for use for 2010
compliance purposes for the biomass-based diesel standard. We request
comment on this approach.
We propose to use information contained in the RR and D codes of
RFS1 RINs to determine how those RINs should be treated under RFS2. The
RR code is used to identify the Equivalence Value of each renewable
fuel, and under RFS1 these Equivalence Values are unique to specific
types of renewable fuel. For instance, biodiesel (mono alkyl ester) has
an Equivalence Value of 1.5, and non-ester renewable diesel has an
Equivalence Value of 1.7, and both of these fuels may be valid for
meeting the biomass-based diesel standard under RFS2. Likewise, RINs
generated for cellulosic biomass ethanol in 2009 must be identified
with a D code of 1, and these fuels may be valid for meeting the
cellulosic biofuel standard under RFS2. Our proposed treatment of 2009
RINs in 2010 is shown in Table III.G.3.a-1.
Table III.G.3.a-1--Proposed Treatment of Excess 2009 RINs in 2010
------------------------------------------------------------------------
Excess 2009 RINs Treatment in 2010
------------------------------------------------------------------------
RFS1 RINs with RR code of 15 or 17........ Equivalent to RFS2 RINs with
D code of 2.
RFS1 RINs with D code of 1................ Equivalent to RFS2 RINs with
D code of 1.
All other RFS1 RINs....................... Equivalent to RFS2 RINs with
D code of 4.
------------------------------------------------------------------------
Although we have discussed the issue of RFS1 RINs being used for
RFS2 purposes in the context of our proposal that the RFS2 program be
effective on January 1, 2010, we would expect a similar treatment of
RFS1 RINs for RFS2 compliance purposes if the RFS2 effective date is
delayed. In that case RFS1 RINs generated in 2010 would be available to
show compliance for both the 2010 and 2011 compliance years, in a
manner similar to that described above.
[[Page 24963]]
b. Deficit Carryovers From the RFS1 Program to RFS2
If the RFS2 program goes into effect on January 1, 2010, the
calculation of RVOs in 2009 under the existing regulations will be
somewhat different than the calculation of RVOs in 2010 under RFS2. In
particular, 2009 RVOs will be based upon gasoline production only,
while 2010 RVOs would be based on volumes of gasoline and diesel. As a
result, 2010 compliance demonstrations that include a deficit carried
over from 2009 will combine obligations calculated on two different
bases.
We do not believe that deficits carried over from 2009 to 2010
would undermine the goals of the program in requiring specific volumes
of renewable fuel to be used each year. Although RVOs in 2009 and 2010
would be calculated differently, obligated parties must acquire
sufficient RINs in 2010 to cover any deficit carried over from 2009 in
addition to that portion of their 2010 obligation which is based on
their 2010 gasoline and diesel production. As a result, the 2009
nationwide volume requirement of 11.1 billion gallons of renewable fuel
will be consumed over the two year period concluding at the end of
2010. Thus, we are not proposing special treatment for deficits carried
over from 2009 to 2010.
We propose that a deficit carried over from 2009 to 2010 would only
affect a party's total renewable fuel obligation in 2010
(RVORF,i as discussed in Section III.G.1), as the 2009
obligation is for total renewable fuel use, not a subcategory. The RVOs
for cellulosic biofuel, biomass-based diesel, or advanced biofuel would
not be affected, as they do not have parallel obligations in 2009 under
RFS1.
If the RFS2 start date is delayed to be later than January 1, 2010,
we expect that the same principles described above would apply for any
deficit calculated under the RFS1 program and carried forward to RFS2.
4. Alternative Approach to Designation of Obligated Parties
Under RFS1, obligated parties who are subject to the standard are
those that produce or import finished gasoline (RFG and conventional)
or unfinished gasoline that becomes finished gasoline upon the addition
of an oxygenate blended downstream from the refinery or importer.
Unfinished gasoline includes reformulated gasoline blendstock for
oxygenate blending (RBOB), and conventional gasoline blendstock
designed for downstream oxygenate blending (CBOB) which is generally
sub-octane conventional gasoline. The volume of any other unfinished
gasoline or blendstock, such as butane, is not included in the volume
used to determine the RVO, except where the blendstock is combined with
other blendstock or finished gasoline to produce finished gasoline,
RBOB, or CBOB. Thus, parties downstream of a refinery or importer are
only obligated parties to the degree that they use non-renewable
blendstocks to make finished gasoline, RBOB, or CBOB.
The approach we took for RFS1 was based on our expectation at that
time that there would be an excess of RINs at low cost, and our belief
that the ability of RINs to be traded freely between any parties once
separated from renewable fuel would provide ample opportunity for
parties who were in need of RINs to acquire them from parties who had
excess. We also pointed out that the designation of ethanol blenders as
obligated parties would have greatly expanded the number of regulated
parties and increased the complexity of the RFS program beyond that
which was necessary to carry out the renewable fuels mandate under CAA
section 211(o).
Following the new requirements under EISA, the required volumes of
renewable fuel will be increasing significantly above the levels
required under RFS1. These higher volumes are already resulting in
changes in the demand for RINs and operation of the RIN market. First,
obligated parties who have excess RINs are increasingly opting to
retain rather than sell them to ensure they have a sufficient number
for the next year's compliance. Second, since all gasoline is expected
to contain ethanol by 2013, few blenders would be able to avoid taking
ownership of RINs by that time under the existing definition of
obligated party. As a result, by 2013 essentially every blender would
be a regulated party who is subject to recordkeeping and reporting
requirements, and thus the additional burden of demonstrating
compliance with the standard could be small. Third, major integrated
refiners who operate gasoline marketing operations have direct access
to RINs for ethanol blended into their gasoline, while refiners whose
operations are focused primarily on producing refined products do not
have such direct access to RINs. The result is that in some cases there
are significant disparities between obligated parties in terms of
opportunities to acquire RINs. If those that have excess RINs are
reluctant to sell them, those who are seeking RINs may be forced to
market a disproportionate share of E85 in order to gain access to the
RINs they need for compliance. If obligated parties seeking RINs cannot
acquire a sufficient number, they can only carry a deficit into the
following year, after which they would be in noncompliance if they
could not acquire sufficient RINs. The result might be a much higher
price for RINs (and fuel) in the marketplace than would be expected
under a more liquid market.
Given the change in circumstances brought about through EISA, it
may be appropriate to consider a change in the way that obligated
parties are defined to more evenly align a party's access to RINs with
that party's obligations under the RFS2 program. The most
straightforward approach would be to eliminate RBOB and CBOB from the
list of fuels that are subject to the standard, such that a party's RVO
would be based only on the non-renewable volume of finished gasoline or
diesel that he produces or imports. Parties that blend ethanol into
RBOB and CBOB to make finished gasoline would thus be obligated
parties, and their RVOs would be based upon the volume of RBOB and CBOB
prior to ethanol blending. Traditional refiners that convert crude oil
into transportation fuels would only have an RVO to the degree that
they produced finished gasoline or diesel, with all RBOB and CBOB sold
to another party being excluded from the calculation of their RVO.
Since essentially all gasoline is expected to be E10 within the
next few years (see discussion in Section V.D.2 below), this approach
would effectively shift the obligation for all gasoline from refiners
and importers to ethanol blenders (who in many cases are still the
refiners). However, this approach by itself would maintain the
obligation for diesel on refiners and importers. Thus, a variation of
this approach would be to move the obligations for all gasoline and
diesel downstream to parties who supply finished transportation fuels
to retail outlets or to wholesale purchaser-consumer facilities. This
variation would have the additional effect of more closely aligning
obligations and access to RINs for parties that blend biodiesel and
renewable diesel into petroleum-based diesel.
We are not proposing to eliminate RBOB and CBOB from the list of
fuels that are subject to the standard in today's notice since it would
result in a significant change in the number of obligated parties and
the movement of RINs. Many parties that are not obligated under the
current RFS program would become obligated, and would be forced to
implement new systems for determining and reporting compliance.
Nevertheless, it would have certain advantages. Currently, blenders
[[Page 24964]]
that are not obligated parties are profiting from the sale of RINs they
acquire through splash blending of ethanol. By eliminating RBOB and
CBOB from the list of obligated fuels, these blenders would become
directly responsible for ensuring that the volume requirements of the
RFS program are met, and the cost of meeting the standard would be more
evenly distributed among parties that blend renewable fuel into
gasoline. With obligations placed more closely to the points in the
distribution system where RINs are made available, the overall market
prices for RINs may be lowered and consequently the cost of the program
to consumers may be reduced.
While eliminating the categories of RBOB and CBOB from the list of
obligated fuels would result in a significant change in the
distribution of obligations among transportation fuel producers, it
could help to ensure that the RIN market functions as we originally
intended. As a result, RINs would more directly be made available to
the parties that need them for compliance. This is similar to the goal
of the direct transfer approach to RIN distribution as described in the
proposed rulemaking for the RFS1 program and presented again in Section
III.H.4 below. We request comment on the degree to which access to RINs
is a concern among current obligated parties. Since either the
elimination of RBOB and CBOB from the list of obligated fuels or the
direct transfer approach to RIN distribution could both accomplish the
same goal, we request comment on which one would be more appropriate,
if any.
We have also considered a number of alternative approaches that
could be used to help ensure that obligated parties can demonstrate
compliance. For instance, one alternative approach would leave our
proposed definitions for obligated parties in place, but would add a
regulatory requirement that any party who blends ethanol into RBOB or
CBOB must transfer the RINs associated with the ethanol to the original
producer of the RBOB or CBOB. However, we believe that such an approach
would be both inappropriate and difficult to implement. RBOB and CBOB
is often transferred between multiple parties prior to ethanol
blending. As a result, a regulatory requirement for RIN transfers back
to the original producer would necessitate an additional tracking
requirement for RBOB and CBOB so that the blender would know the
identity of the original producer. It would also be difficult to ensure
that RINs representing the specific category of renewable fuel blended
were transferred to the producer of the RBOB or CBOB, given the
fungible nature of RINs assigned to batches of renewable fuel. For
these reasons, we do not believe that this alternative approach would
be appropriate.
In another alternative approach, some RINs that expire without
being used for compliance by an obligated party could be used to reduce
the nationwide volume of renewable fuel required in the following year.
We would only reduce the required volume of renewable fuel to the
degree that sufficient RINs had been generated to permit all obligated
parties to demonstrate compliance, but some obligated parties
nevertheless could not acquire a sufficient number of RINs. Moreover,
only RINs that were expiring would be used to reduce the nationwide
volume for the next year. This alternative approach would ensure that
the volumes required in the statute would actually be produced and
would prevent the hoarding of RINs from driving up demand for renewable
fuel. However, it would also reduce the impact of the valid life limit
for RINs.
We could lower the 20% rollover cap applicable to the use of
previous-year RINs to a lower value, such as 10%. This approach would
provide a greater incentive for obligated parties with excess RINs to
sell them but would further restrict a potentially useful means of
managing an obligated party's risk. As described in Section IV.D, we
are not proposing any changes in the 20% rollover cap in today's
notice. However, we request comment on it.
Finally, another change to the program that would not change the
definition of obligated parties, but could help address the disparity
of access to RINs among obligated parties, would be to remove the
requirement developed under RFS1 that RINs be transferred with
renewable fuel volume by the renewable fuel producers and importers.
This alternative is discussed further in Section III.H.4 below.
H. Separation of RINs
We propose that most of the RFS1 provisions regarding the
separation of RINs from volumes of renewable fuel be retained for RFS2.
However, the modifications in EISA will require a number of changes,
primarily to the treatment of RINs associated with nonroad renewable
fuel and renewable fuels used in heating oil and jet fuel. Our approach
to the separation of RINs by exporters must also be modified to account
for the fact that there would be four categories of renewable fuel
under RFS2.
1. Nonroad
Under RFS1, RINs associated with renewable fuels used in nonroad
vehicles and engines downstream of the renewable fuel producer are
required to be retired by the party who owns the renewable fuel at the
time of blending. This provision derived from the EPAct definition of
renewable fuel which was limited to fuel used to replace fossil fuel
used in a motor vehicle. EISA however expands the definition of
renewable fuel, and ties it to the definition of transportation fuel,
which is defined as any ``fuel for use in motor vehicles, motor vehicle
engines, nonroad vehicles, or nonroad engines (except for ocean-going
vessels). To implement these changes, the proposed RFS2 program
eliminates the RFS1 RIN retirement requirement for renewable fuels used
in nonroad applications, with the exception of RINs associated with
renewable fuels used in ocean-going vessels.
2. Heating Oil and Jet Fuel
EISA defined `additional renewable fuel' as ``fuel that is produced
from renewable biomass and that is used to replace or reduce the
quantity of fossil fuel present in home heating oil or jet fuel.'' \40\
While we are proposing that fossil-based heating oil and jet fuel would
not be included in the fuel used by a refiner or importer to calculate
their RVO, we are proposing that renewable fuels used as or in heating
oil and jet fuel may generate RINs for credit purposes. Thus, the RINs
of a renewable fuel, such as biodiesel, that is blended into heating
oil continue to be valid. See also discussion in Section III.B.1.e.
---------------------------------------------------------------------------
\40\ EISA, Title II, Subtitle A-Renewable Fuel Standard, Section
201.
---------------------------------------------------------------------------
3. Exporters
Under RFS1, exporters are assigned an RVO representing the volume
of renewable fuel that has been exported, and they are required to
separate all RINs that have been assigned to fuel that is exported.
Since there is only one standard, there is only one possible RVO
applicable to exporters.
Under RFS2, there are four possible RVOs corresponding to the four
categories of renewable fuel (cellulosic biofuel, biomass-based diesel,
advanced biofuel, total renewable fuel). However, given the fungible
nature of the RIN system and the fact that an assigned RIN transferred
with a volume of renewable fuel may not be the same RIN that was
originally generated to represent that volume, there is no way for an
exporter to determine from an assigned RIN which of the four categories
applies to
[[Page 24965]]
an exported volume. In order to determine its RVOs, the only
information available to the exporter is the type of renewable fuel
that he is exporting.
For RFS2, we are proposing that exporters use the fuel type and its
associated volume to determine his applicable RVO. To accomplish this,
an exporter must know which of the four renewable fuel categories
applies to a given type of renewable fuel. We are proposing that all
biodiesel (mono alkyl esters) and renewable diesel would be categorized
as biomass-based diesel (D code of 4), and that exported volumes of
these two fuels would be used to determine the exporter's RVO for
biomass-based diesel. For all other types of renewable fuel, the most
likely category for most of the phase-in period of the RFS2 program is
general renewable fuel, and as a result we propose that all other types
of renewable fuel be used to determine the exporter's RVO for total
renewable fuel. Our proposed approach is provided at Sec. 80.1430. We
recognize that by 2022 the required volume of cellulosic biofuel will
exceed the required volume of general renewable fuel that is in excess
of the advanced biofuel requirements. Thus we request comment on
requiring all or some portion of renewable fuels other than biodiesel
and renewable diesel to be categorized as cellulosic biofuel in 2022
and beyond.
An alternative approach could be required that would more closely
estimate the amount of exported renewable fuels that fall into the four
categories defined by EISA. In this alternative, the total nationwide
volumes required in each year (see Table II.A.1-1) would be used to
apportion specific types of renewable fuel into each of the four
categories. For example, exported ethanol may have originally been
produced from cellulose to meet the cellulosic biofuel requirement,
from corn to meet the total renewable fuel requirement, or may have
been imported as advanced biofuel. If ethanol were exported, we could
divide the exported volume into three RVOs for cellulosic biofuel,
advanced biofuel, and total renewable fuel using the same proportions
represented by the national volume requirements for that year. However,
we believe that this alternative approach would add considerable
complexity to the compliance determinations for exporters without
necessarily adding more precision. Given the expected small volumes of
exported renewable fuel, this added complexity does not seem warranted
at this time. Nevertheless, we request comment on it.
4. Alternative Approaches to RIN Transfers
In the NPRM for the RFS1 rulemaking, we presented a variety of
approaches to the transfer of RINs, ultimately requiring that RINs
generated by renewable fuel producers and importers must be assigned to
batches of renewable fuel and transfered along with those batches.
However, given the higher volumes required under RFS2 and the resulting
expansion in the number of regulated parties, we believe that two of
the alternative approaches to RIN transfers should be considered for
RFS2. Our proposal for an EPA-moderated RIN trading system (EMTS) may
also support the implementation of one of these approaches.
In one of the alternative approaches, we would entirely remove the
restriction established under the RFS1 rule requiring that RINs be
assigned to batches of renewable fuel and transferred with those
batches. Instead, renewable fuel producers could sell RINs (with a K
code of 2 rather than 1) separately from volumes of renewable fuel to
any party. This approach could significantly streamline the tracking
and trading of RINs. For instance, there would no longer be a need for
K-codes and restrictions on separation of RINs, there would only be a
single RIN market rather than two (one for RINs assigned to volume and
another for separated RINs), there would be no need for volume/RIN
balance calculations at the end of each quarter, and there would be no
need for restrictions on the number of RINs that can be transfered with
each gallon of renewable fuel. As described more fully in Section
III.B.4.b.ii, this approach could also provide a greater incentive for
producers to demonstrate that the renewable biomass definition has been
met for their feedstocks. As discussed in Section III.G.4, this approch
could help level the playing field among obligated parties for access
to RINs regardless of whether they market a substantial volume of
gasoline or not. However, as discussed in the RFS1 rulemaking, this
approach could also place obligated parties at greater risk of market
manipulation by renewable fuel producers.
In order to address some of the concerns raised about allowing
producers and importers to separate RINs from their volume, in the NPRM
for the RFS1 rulemaking we also presented an alternative concept for
RIN distribution in which producers and importers of renewable fuels
would be required to transfer the RIN, but only to an obligated party
(see 71 FR 55591). This ''direct transfer'' approach would require
renewable fuel producers to transfer RINs with renewable fuel for all
transactions with obligated parties, and sell all other RINs directly
to obligated parties on a quarterly basis for any renewable fuel
volumes that were not sold directly to obligated parties. Only
renewable fuel producers, importers, and obligated parties would be
allowed to own RINs, and only obligated parties could take ownership of
RINs from producers and importers. This approach would spare marketers
and distributors of renewable fuel from the burdens associated with
transferring RINs with batches, and thus would eliminate the tracking,
recordkeeping and reporting requirements that would continue to be
applicable to them if RINs are transferred through the distribution
system as required under the RFS1 program.
Under the direct transfer alternative, the renewable fuel producer
or importer would be required to transfer the RINs associated with his
renewable fuel to an obligated party who purchases the renewable fuel.
The RINs associated with any renewable fuel that is not directly
transferred to an obligated party would not be transferred with the
fuel as required under the RFS1 program. Instead, the renewable fuel
producer or importer would be required to sell the RINs directly to an
obligated party. Any RINs not sold in this way would be required to be
offered for sale to all obligated parties through a public auction.
This could be through an EPA moderated trading system, an existing
internet auction web site, or through another auction mechanism
implemented by a renewable fuel producer.
Although we believe that the direct transfer approach has merit,
many of the concerns laid out in the RFS1 NPRM remain valid today. In
particular, the auctions would need to be regulated in some way to
ensure that RIN generators could not withhold RINs from the market by
such means as failing to adequately advertise the time and location of
an auction, by setting the selling price too high, by specifying a
minimum number of bids before selling, by conducting auctions
infrequently, by having unduly short bidding windows, etc. We seek
comment on how we could regulate such auctions to ensure that obligated
parties could acquire sufficient RINs for compliance purposes in a
timely manner.
Our proposed EPA-moderated RIN trading system (see Section IV.E)
could help to make the direct transfer approach feasible. By creating
accounts
[[Page 24966]]
in a centralized system within which all RIN transfers between parties
would be made, it may be more straightforward for obligated parties to
identify available RINs owned by producers and importers, and to bid on
those RINs. Therefore, while we are not proposing the direct transfer
approach in today's action, we nevertheless request comment on it.
5. Neat Renewable Fuel and Renewable Fuel Blends Designated as
Transportation Fuel, Home Heating Oil, or Jet Fuel
Under RFS1, RINs must, with limited exceptions, be separated by an
obligated party taking ownership of the renewable fuel, or by a party
that blends renewable fuel with gasoline or diesel. In addition, a
party that designates neat renewable fuel as motor vehicle fuel may
separate RINs associated with that fuel if the fuel is in fact used in
that manner without further blending. For purposes of the RFS program,
``neat renewable fuel'' is defined in 80.1101(p) as ``a renewable fuel
to which only de minimis amounts of conventional gasoline or diesel
have been added.'' One exception to these provisions is that biodiesel
blends in which diesel constitutes less than 20 volume percent are
ineligible for RIN separation by a blender. As noted in the preamble to
the final RFS1 regulations, EPA understands that in the vast majority
of cases, biodiesel is blended with diesel in concentrations of 80
volume percent or less.
However, in order to account for situations in which biodiesel
blends of 81 percent or greater may be used as motor vehicle fuel
without ever having been owned by an obligated party, EPA is proposing
to change the applicability of the RIN separation provisions for RFS2.
EPA is proposing that 80.1429(b)(4) allow for separation of RINs for
neat renewable fuel or blends of renewable fuel and or diesel fuel that
the party designates as transportation fuel, home heating oil, or jet
fuel, provided the neat renewable fuel or blend is used in the
designated form, without further blending, as transportation fuel, home
heating oil, or jet fuel. As in RFS1, those parties that blend
renewable fuel with gasoline or diesel fuel (in a blend containing less
than 80 percent biodiesel would in all cases be required to separate
RINs pursuant 80.1429(b)(2).
Thus, for example, under these proposed regulations, if a party
intends to separate RINs from a volume of B85, the party must designate
the blend for use as transportation fuel, home heating oil, or jet fuel
and the blend must be used in its designated form without further
blending. The party would also be required maintain records of this
designation pursuant to 80.1451(b)(5). Finally, the party would be
required to comply with the proposed PTD requirements in
80.1453(a)(5)(iv), which serve to notify downstream parties that the
volume of fuel has been designated for use as transportation fuel, home
heating oil, or jet fuel, and must be used in that designated form
without further blending. Parties could separate RINs at the time they
complied with the designation and PTD requirements, and would not need
to physically track ultimate fuel use.
EPA requests comment on this proposed approach to RIN separation.
Additionally, EPA requests comment on an alternative approach to
modifying the current program for separation of RINs. Under this second
approach, 80.1429(b)(2) and (b)(5)would be eliminated as redundant, and
80.1429(b)(4) would be broadened to require separation of RINs for all
neat renewable fuels and all blends of renewable fuels with either
gasoline or diesel, when a party designates such fuel as transportation
fuel, home heating oil or jet fuel, and the fuel is in fact used in
accordance with that designation without further blending. The party
would be required to maintain records that verify the ultimate use of
the fuel as transportation, home heating, or jet fuel. Additionally,
there would be a PTD requirement to inform downstream parties that the
fuel has been designated as transportation, home heating, or jet fuel
and may not be further blended. This proposed approach would eliminate
the need for parties to distinguish for purposes of separating RINs
between fuels that are neat or blended or, for biodiesel, between
blends of E80 and below or E81 and above.
I. Treatment of Cellulosic Biofuel
1. Cellulosic Biofuel Standard
EISA requires in section 202(e) that the Administrator set the
cellulosic biofuel standard each November for the next year based on
the lesser of the volume specified in the Act or the projected volume
of cellulosic biofuel production for that year. In the event that the
projected volume is less than the amount required in the Act, EPA may
also reduce the applicable volume of the advanced biofuels requirement
by the same or a lesser volume. We intend to examine EIA's projected
volumes and other available data including the production outlook
reports proposed in Section III.K to be submitted to the EPA to decide
the appropriate standard for the following year. The outlook reports
from all renewable fuel producers would assist EPA in determining what
the cellulosic biofuel standard should be and if the advanced biofuel
standard should be adjusted. For years where EPA determines that the
projected volume of cellulosic biofuels is not sufficient to meet the
levels in EISA we will consider the availability of other advanced
biofuels in deciding whether to lower the advanced biofuel standard as
well.
2. EPA Cellulosic Allowances for Cellulosic Biofuel
Whenever EPA sets the cellulosic biofuel standard at a level lower
than that required in EISA, EPA is required to provide a number of
cellulosic credits for sale that is no more than the volume used to set
the standard. Congress also specified the price for such credits:
adjusted for inflation, they must be offered at the price of the higher
of 25 cents per gallon or the amount by which $3.00 per gallon exceeds
the average wholesale price of a gallon of gasoline in the United
States. The inflation adjustment will be for years after 2008. We
propose that the inflation adjustment would be based on the Consumer
Price Index for All Urban Consumers (CPI-U) for All Items expenditure
category as provided by the Bureau of Labor Statistics.\41\
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\41\ See U.S. Department of Labor, Bureau of Labor Statistics
(BLS), Consumer Price Index Web site at: http://www.bls.gov/cpi/.
---------------------------------------------------------------------------
Congress afforded the Agency considerable flexibility in
implementing the system of cellulosic biofuel credits. EISA states EPA;
``shall include such provisions, including limiting the credits' uses
and useful life, as the Administrator deems appropriate to assist
market liquidity and transparency, to provide appropriate certainty for
regulated entities and renewable fuel producers, and to limit any
potential misuse of cellulosic biofuel credits to reduce the use of
other renewable fuels, and for such other purposes as the Administrator
determines will help achieve the goals of this subsection.''
Though EISA gives EPA broad flexibility, we believe the best way to
accomplish the goals of providing certainty to both the cellulosic
biofuel industry and the obligated parties is to propose credits with
few degrees of freedom. We believe this would prevent speculation in
the market and provide certainty for investments in real cellulosic
biofuels.
Specifically, we propose that the credits would be called
allowances so
[[Page 24967]]
that there is no confusion with RINs, such allowances would only be
available for the current compliance year for which we have waived some
portion of the cellulosic biofuel standard, they would only be
available to obligated parties, and they would be nontransferable and
nonrefundable. Further, we propose that obligated parties would only be
able to purchase allowances up to the level of their cellulosic biofuel
RVO less the number of cellulosic biofuel RINs that they own. This
would help ensure that every party that needs to meet the cellulosic
biofuel standard will have equal access to the allowances. A company
would also then only use an allowance to meet its total renewable and
advanced biofuel standards if it used the allowance for the cellulosic
biofuel standard. We believe that if a company can only purchase as
many allowances as it needs to meet its cellulosic biofuel obligation,
it can not hinder another obligated party from meeting the standard and
therefore every company that needs to meet the standard will have equal
access to the allowances in the event that they do not acquire
sufficient cellulosic biofuel RINs. If we were to allow a company to
purchase more allowances than they needed, another company may not be
able to meet the standard which we believe was not the intent of
Congress.
We also propose that these allowances would be offered in a generic
format rather than a serialized format, like RINs. Allowances would be
purchased from the EPA at the time that an obligated party submits its
annual compliance demonstration to the EPA and establishes that it owns
insufficient cellulosic biofuel RINs to meet its cellulosic biofuel
RVO. A company owning cellulosic biofuel RINs and cellulosic allowances
may use both types of credits if desired to meet their RVOs, but unlike
RINs they would not be able to carry allowances over to the next
calendar year.
Congress refers to allowances as ``cellulosic biofuel credits,''
with no indication that the ``credits'' should be given any less role
in meeting a party's obligations under the CAA section 211(o) than
would the purchase and use of a cellulosic biofuel RIN that reflects
actual production and use of cellulosic biofuel. Because cellulosic
biofuel RINs can be used to meet the advanced biofuel and total
renewable fuel standards in addition to the cellulosic biofuel
standard, we propose that cellulosic biofuel allowances also be
available for use in meeting those three standards.
We propose that the wholesale price of gasoline will be based on
the average monthly bulk (refinery gate) price of gasoline using data
from the most recent twelve months of data from EIA's annual cellulosic
ethanol forecast each October.\42\ Thus we will set the allowance price
for the following year each November along with the cellulosic biofuel
standard for the following year. We seek comment on using the average
monthly rack (terminal) price for the same period and changing the
allowance price as often as quarterly. Though EISA allows EPA to change
the price as often as quarterly we believe this will lead to
speculation which may introduce more uncertainty for the obligated
parties and the cellulosic biofuel industry.
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\42\ More information on wholesale gasoline prices can be found
on the Department of Energy's (DOE), Energy Information
Administration's (EIA) Web site at: http://tonto.eia.doe.gov/dnav/pet/pet_pri_allmg_d_nus_PBS_cpgal_m.htm.
---------------------------------------------------------------------------
3. Potential Adverse Impacts of Allowances
While the credit provisions of section 202(e) of EISA ensure that
there is a predictable upper limit to the price that cellulosic biofuel
producers can charge for a gallon of cellulosic biofuel and its
assigned RIN, there may be circumstances in which this provision has
other unintended impacts. For instance, if we made all cellulosic
allowances available to any obligated party, one obligated party could
purchase more allowances than he needs to meet his cellulosic biofuel
RVO and then sell the remaining allowances at an inflated price to
other obligated parties. Thus, we are proposing that each obligated
party could only purchase allowances from the EPA up to the level of
their cellulosic biofuel RVO. However, even with this restriction an
obligated party could still purchase both cellulosic biofuel volume
with its assigned RINs sufficient to meet its cellulosic biofuel RVO,
and also purchase allowances from the EPA. In this case, the obligated
party would effectively be using allowances as a replacement for corn
ethanol rather than cellulosic biofuel. To prevent this, we are
proposing an additional restriction: an obligated party could only
purchase allowances from the EPA to the degree that it establishes it
owns insufficient cellulosic biofuel RINs to meet its cellulosic
biofuel RVO. This approach forces obligated parties to apply all their
cellulosic biofuel RINs to their cellulosic biofuel RVO before appying
any allowances to their cellulosic biofuel RVO.
However, even with these proposed restrictions on the purchase and
application of allowances, the statutory provision may not operate as
intended. For instance, if the combination of cellulosic biofuel volume
price and RIN price is low compared to that for corn-ethanol, a small
number of obligated parties could purchase more cellulosic biofuel than
they need to meet their cellulosic biofuel RVOs and could use the
additional cellulosic biofuel RINs to meet their advanced biofuel and
total renewable fuel RVOs. Other obligated parties would then have no
access to cellulosic biofuel volume nor cellulosic biofuel RINs, and
would be forced to purchase allowances from the EPA. This situation
would have the net effect of allowances replacing imported sugarcane
ethanol and/or corn-ethanol rather than cellulosic biofuel.
Moreover, under certain conditions it may be possible for the
market price of corn-ethanol RINs to be significantly higher than the
market price of cellulosic biofuel RINs, as the latter is limited in
the market by the price of EPA-generated allowances according to the
statutory formula described in Section III.I.2 above. Under some
conditions, this could result in a competitive disadvantage for
cellulosic biofuel in comparison to corn ethanol. For instance, if
gasoline prices at the pump are significantly higher than ethanol
production costs, while at the same time corn-ethanol production costs
are lower than cellulosic ethanol production costs, profit margins for
corn-ethanol producers would be larger than for cellulosic ethanol
producers. Under these conditions, while obligated parties may still
purchase cellulosic ethanol volume and its associated RIN rather than
allowances, cellulosic ethanol producers would realize lower profits
than corn-ethanol producers due to the upper limit placed on the price
of cellulosic biofuel RINs through the pricing formula for allowances.
For a newly forming and growing cellulosic biofuel industry, this
competitive disadvantage could make it more difficult for investors to
secure funding for new projects, threatening the ability of the
industry to reach the statutorily mandated volumes.
We have not established the likelihood that these circumstances
would arise in practice, and we request comment on the specific market
conditions that could lead to them. Nevertheless, we have explored a
variety of ways that we could modify the RFS program structure to
mitigate these potential negative outcomes. For instance, as mentioned
in Section III.I.2 above, we are proposing that each
[[Page 24968]]
cellulosic allowance could be used to meet an obligated party's RVOs
for cellulosic biofuel, advanced biofuel, and total renewable fuel.
However, we could restrict the applicability of allowances to only the
cellulosic biofuel RVO. This approach could help ensure that demand for
imported sugarcane ethanol and corn ethanol does not fall in the event
that a small number of obligated parties purchase all available
cellulosic biofuel volume, compelling the remaining obligated parties
to purchase allowances. However, this approach could also have the
effect of making the advanced biofuel and total renewable fuel
standards more stringent. This could occur as obligated parties are
forced to buy additional imported sugarcane ethanol and corn ethanol to
make up for the fact that the allowances they purchase from the EPA
would not apply to the advanced biofuel and total renewable fuel
standards.
As a variation to this approach, while still restricting the
applicability of allowances to only the cellulosic biofuel RVO, we
could similarly make cellulosic biofuel RINs applicable to only the
cellulosic biofuel RVO. This approach would ensure that the compliance
value of both cellulosic biofuel RINs and allowances is the same, but
would necessarily result in an increase in the effective stringency of
the advanced biofuel and total renewable fuel standards.
Finally, we could institute a ``dual RIN'' approach to cellulosic
biofuel that has the potential to address some of the shortcomings of
the previous approaches. In this approach, both cellulosic biofuel RINs
(with a D code of 1) and allowances could only be applied to an
obligated party's cellulosic biofuel RVO, but producers of cellulosic
biofuel would also generate an additional RIN representing advanced
biofuel (with a D code of 3). The producer would only be required to
transfer the advanced biofuel RIN with a batch of cellulosic biofuel,
and could retain the cellulosic biofuel RIN for separate sale to any
party.\43\ The cellulosic biofuel and its attached advanced biofuel RIN
would then compete directly with other advanced biofuel and its
attached advanced biofuel RIN, while the separate cellulosic biofuel
RIN would have an independent market value that would be effectively
limited by the pricing formula for allowances as described in Section
III.I.2. However, this approach would be a more significant deviation
from the RIN generation and transfer program structure that was
developed cooperatively with stakeholders during RFS1. It would provide
cellulosic biofuel producers with significantly more control over the
sale and price of cellulosic biofuel RINs, which was one of the primary
concerns of obligated parties during the development of RFS1.
---------------------------------------------------------------------------
\43\ The cellulosic biofuel RIN would be a separated RIN with a
K code of 2 immediately upon generation.
---------------------------------------------------------------------------
Due to the drawbacks of each of these potential changes to the RFS
program structure, we are not proposing any of them in today's NPRM.
However, we request comment on whether any of them, or alternatives,
could address the adverse situations described above. We also request
comment on the degree to which the adverse situations are likely to
occur, and the degree of severity of the negative impacts that could
result.
J. Changes to Recordkeeping and Reporting Requirements
1. Recordkeeping
As with the existing renewable fuel standard program, recordkeeping
under this proposed program will support the enforcement of the use of
RINs for compliance purposes. As with the existing renewable fuels
program, we are proposing that parties be afforded significant freedom
with regard to the form that product transfer documents (PTDs) take. We
propose to permit the use of product codes as long as they are
understood by all parties. We propose that product codes may not be
used for transfers to truck carriers or to retailers or wholesale
purchaser-consumers. We propose that parties must keep copies of all
PTDs they generate and receive, as well as copies of all reports
submitted to EPA and all records related to the sale, purchase,
brokering or transfer or RINs, for five (5) years. We also propose that
parties must also keep copies of records that relate to flexibilities,
as described in Section IV.A. through C. of this preamble. Such
flexibilities are related to attest engagements, the upward delegation
of RIN-separating responsibilities, and various small business oriented
provisions. Upon request, parties would be responsible for providing
their records to the Administrator or the Administrator's authorized
representative. We would reserve the right to request to receive
documents in a format that we can read and use.
In Section IV.E. of this preamble, we propose an EPA-Moderated
Trading System for RINs. If adopted, the new system would allow for
real-time reporting of RIN generation (i.e., batch reports by producers
and importers) and RIN transactions.
2. Reporting
Under the existing renewable fuels program, obligated parties,
exporters of renewable fuel, producers and importers of renewable
fuels, and any party who owns RINs must report appropriate information
to EPA on a quarterly and/or annual basis. We are proposing a change in
the schedule for submission of producers' and importers' batch reports,
and for the submission of RIN transaction reports. This proposed change
in schedule, which is discussed in great detail in Section IV.E. of
this preamble, is effective for 2010 only. We are proposing that, for
2010, these reports (which were submitted quarterly under RFS1) be
submitted monthly rather than quarterly. The reason for proposing
monthly reporting for 2010 is to minimize difficulties associated with
invalid RINs, while the EPA-Moderated Trading System is still under
development. As described in detail in IV.E. we intend to have an EPA-
Moderated Trading System fully operational by 2011. At the time that
system becomes fully operational, all batch and RIN transactional
reporting would be submitted in real time. The following deadlines
would apply to ``real time,' monthly, quarterly, and annual reports.
``Real time'' reports within the EPA-Moderating Trading System
would be submitted within three (3) business days of a reportable event
(e.g. generation of a RIN, a transaction occurring involving a RIN).
Real time reporting would apply to batch reports submitted by producers
and importers who generate RINs and to to RIN transaction reports
submitted in 2011 and future years.
Monthly reports would be submitted according to the following
schedule:
Table III.J.2-1--Monthly Reporting Schedule
------------------------------------------------------------------------
Month covered by report Due date for report
------------------------------------------------------------------------
January................................... February 28.
February.................................. March 31.
March..................................... April 30.
April..................................... May 31.
May....................................... June 30.
June...................................... July 31.
July...................................... August 31.
August.................................... September 30.
September................................. October 31.
October................................... November 30.
November.................................. December 31.
December.................................. January 31.
------------------------------------------------------------------------
The monthly reporting schedule would apply to batch reports
submitted by producers and importers who generate RINs and to RIN
transaction reports submitted for 2010 only.
[[Page 24969]]
Quarterly reports would be submitted on the following schedule:
Table III.J.-2--Quarterly Reporting Schedule
------------------------------------------------------------------------
Quarter covered by report Due date for report
------------------------------------------------------------------------
January-March............................. May 31.
April-June................................ August 31.
July-September............................ November 30.
October-December.......................... February 28.
------------------------------------------------------------------------
Quarterly reports include summary reports related to RIN
activities.
Annual reports (covering January through December) would continue
to be due on February 28. Annual reports include compliance
demonstrations by obligated parties.
Under this proposed rule, the universe of reporting parties would
grow, but we propose similar reporting to existing reporting. We
believe that the proposed EPA-Moderating Trading System will make
reporting easier for most parties. Existing reporting forms and
instructions are posted at http://www.epa.gov/otaq/regs/fuels/rfsforms.htm. You may wish to refer to these existing forms in
preparing your comments on this proposal.
Simplified, secure reporting is currently available through our
Central Data Exchange (CDX). CDX permits us to accept reports that are
electronically signed and certified by the submitter in a secure and
robustly encrypted fashion. Using CDX eliminates the need for wet ink
signatures and reduces the reporting burden on regulated parties. It is
our intention to continue to encourage the use of CDX for reporting
under this proposed program as well.
Due to the criteria that renewable fuel producers and importers
must meet in order to generate RINs under RFS2, and due to the fact
that renewable fuel producers and importers must have documentation
about whether their feedstock(s) meets the definition of ``renewable
biomass,'' we propose several changes to the RFS1 RIN generation
report. We propose to make the report a more general report on
renewable fuel production in order to capture information on all
batches of renewable fuel, whether or not RINs are generated for them.
All renewable fuel producers and importers above 10,000 gallons per
year would report to EPA on each batch of their fuel and indicate
whether or not RINs are generated for the batch. If RINs are generated,
the producer or importer would be required to certify that his
feedstock meets the definition of ``renewable biomass.'' If RINs are
not generated, the producer or importer would be required to state the
reason for not generating RINs, such as they have documentation that
states that their feedstock did not meet the definition of ``renewable
biomass,'' or the fuel pathway used to produce the fuel was such that
the fuel did not qualify for any D code (see Section III.B.4.b for a
discussion about demonstrating whether or not feedstock meets the
definition of ``renewable biomass''). For each batch of renewable fuel
produced, we also propose to require information about the types and
volumes of feedstock used and the types and volumes of co-products
produced, as well as information about the process or processes used.
This information is necessary to confirm that the producer or importer
assigned the appropriate D code to their fuel and that the D code was
consistent with their registration information.
Two minor additions are being incorporated into the RIN transaction
report. First, for reports of RINs assigned to a volume of renewable
fuel, we are asking that the volume of renewable fuel be reported.
Additionally, we propose that RIN price information be submitted for
transactions involving both separated RINs and RINs assigned to a
renewable volume. This information is not collected under RFS1, but we
believe this information has great programmatic value to EPA because it
may help us to anticipate and appropriately react to market disruptions
and other compliance challenges, will be beneficial when setting future
renewable standards, and will provide additional insight into the
market when assessing potential waivers. We anticipate that having
current market information such as total number of RINs produced and
RINs available in the separated market is incomplete. Missing is our
ability to assess the general health and direction of the market and
overall liquidity of RINs. Tracking price trend information will allow
us to identify market inefficiencies and perceptions of RIN supply.
When price information is combined with information from the production
outlook reports, we will be better able to judge realistic expectations
of renewable production and be in a better position when setting and
justifying future renewable standards or pursuing relief through waiver
provisions. Also, we believe the addition of price information will be
highly beneficial to regulated parties. With price information being
noted on transaction reports, buyers and sellers will have an
additional and immediate reference when confirming transactions.
Additionally, we believe that highly summarized price information
(e.g., the average price of RINs traded) should be available to
regulated parties, as well, and may help them to anticipate and avoid
market disruptions.
We also propose to make minor changes to compliance reports related
to the identification of types of RINs. Please refer to Section III.B.
of this preamble for a discussion of types of renewable fuels. Also,
please refer to Section III.A. for a discussion of proposed changes to
RINs.
Under our proposed EPA-Moderated Trading System described in
Section IV.E. of this preamble, then there would be a change in
reporting burden on regulated parties that affects the frequency of
reporting and the number of reports. Instead of quarterly and/or annual
contact with EPA, there would be real time contact--i.e., as batches of
renewable fuel are generated or as RINs are transacted. However, we
believe that any burden is offset by the advantage of having a
simplified system for RIN management that will promote the integrity of
RINs and will remove ``guesswork'' now associated with RIN management.
As things are now, a regulated party may experience frustration and
incur expense in trying to track down and correct errors. Once an error
is made, it propagates throughout the distribution system with each
transfer from party to party. By having EPA moderate RIN management, we
believe that errors would be minimized and regulated parties would be
freed of the greater burden to attempt to track down and correct errors
they may have made. Implementation of the EPA-Moderated Trading System
would correspond to real-time reporting of the type of information
contained in the following two quarterly reports: The Renewable Fuel
Production Report, known as the RIN Generation Report or ``batch
report'' under RFS1 (Report Form Template RFS0400), and the RIN
Transaction Report (Report Form Template RFS0200), starting in 2011.
For 2010, we are proposing that the type of information contained in
these two forms be submitted monthly. These and other reports and
instructions related to the existing renewable fuel standard program
(RFS1) are posted at http://www.epa.gov/otaq/regs/fuels/rfsforms.htm.
3. Additional Requirements for Producers of Renewable Natural Gas,
Electricity, and Propane
In addition to the general reporting requirement listed above, we
are proposing an additional item of reporting for producers of
renewable
[[Page 24970]]
natural gas, electricity, and propane who choose to generate and assign
RINs. While producers of renewable natural gas, electricity, and
propane who generate and assign RINs would be responsible for filing
the same reports as other producers of RIN-generating renewable fuels,
we propose that additional reporting for these producers be required to
support the actual use of their products in the transportation sector.
We believe that one simple way to achieve this may be to add a
requirement that producers of renewable natural gas, electricity, and
propane add the name of the purchaser (e.g., the name of the wholesale
purchaser-consumer (WPC) or fleet) to their quarterly RIN generation
reports and then maintain appropriate records that further identify the
purchaser and the details of the transaction. We are not proposing that
a purchaser who is either a WPC or an end user would have to register
under this scenario, unless that party engages in other activities
requiring registration under this program.
K. Production Outlook Reports
We are also proposing additional reporting--annual production
outlook reports that would be required of all domestic renewable fuel
producers, foreign renewable fuel producers who register to generate
RINs, and importers of covered renewable fuels starting in 2010. These
production outlook reports would be similar to the pre-compliance
reports required under the Highway and Nonroad Diesel programs. These
reports would contain information about existing and planned production
capacity, long-range plans, and feedstocks and production processes to
be used at each production facility. For expanded production capacity
that is planned or underway at each existing facility, or new
production facilities that are planned or underway, the progress
reports would require information on: (1) Strategic planning; (2)
Planning and front-end engineering; (3) Detailed engineering and
permitting; (4) Procurement and Construction; and (5) Commissioning and
startup. These five project phases are described in EPA's June 2002
Highway Diesel Progress Review report (EPA document number EPA420-R-02-
016, located at: www.epa.gov/otaq/regs/hd2007/420r02016.pdf).
The full list of requirements for the proposed production outlook
reports is provided in the proposed regulations at Sec. 80.1449. The
information submitted in the reports would be used to evaluate the
progress that the industry is making towards the renewable fuels volume
goals mandated by EISA and to set the annual cellulosic biofuel,
advanced biofuel, biomass-based diesel, and total renewable fuel
standards (see Section II.A.7 of this preamble). We are proposing that
the annual production outlook reports be due annually by February 28,
beginning in 2010 and continuing through 2022, and we are proposing
that each annual report must provide projected information through
calendar year 2022.
EPA currently receives data on projected flexible-fuel vehicle
(FFV) sales and conversions from vehicle manufacturers; however, we do
not have information on renewable fuels in the distribution system.
Thus, EPA is also considering whether to require the annual submission
of data to facilitate our evaluation of the ability of the distribution
system to deliver the projected volumes of biofuels to petroleum
terminals that are needed to meet the RFS2 standards. We request
comment on the extent to which such information is already publicly
available or can be purchased from a proprietary source. We further
request comment on the extent to which such publicly available or
purchasable data would be sufficient for EPA to make its determination.
To the extent that additional data might be needed, we request comment
on the parties that should be required to report to EPA and what data
should be required. For example, would it be appropriate to require
terminal operators to report to EPA annually on their ability to
receive, store, and blend biofuels into petroleum-based fuels? We
believe that publicly available information on E85 refueling facilities
is sufficient for us to make a determination about the adequacy of such
facilities to support the projected volumes of E85 that would be used
to satisfy the RFS2 standards.
We request comment on the proposed requirement of annual production
outlook reports, and all other aspects mentioned above (e.g., reporting
requirements, reporting dates, etc.).
L. What Acts Are Prohibited and Who Is Liable for Violations?
The prohibition and liability provisions applicable to the proposed
RFS2 program would be similar to those of the RFS1 program and other
gasoline programs. The proposed rule identifies certain prohibited
acts, such as a failure to acquire sufficient RINs to meet a party's
RVOs, producing or importing a renewable fuel that is not assigned a
proper RIN category (or D Code), improperly assigning RINs to renewable
fuel that was not produced with renewable biomass, failing to assign
RINs to qualifying fuel, or creating or transferring invalid RINs. Any
person subject to a prohibition would be held liable for violating that
prohibition. Thus, for example, an obligated party would be liable if
the party failed to acquire sufficient RINs to meet its RVO. A party
who produces or imports renewable fuels would be liable for a failure
to assign proper RINs to qualifying batches of renewable fuel produced
or imported. Any party, including an obligated party, would be liable
for transferring a RIN that was not properly identified.
In addition, any person who is subject to an affirmative
requirement under this program would be liable for a failure to comply
with the requirement. For example, an obligated party would be liable
for a failure to comply with the annual compliance reporting
requirements. A renewable fuel producer or importer would be liable for
a failure to comply with the applicable batch reporting requirements.
Any party subject to recordkeeping or product transfer document (PTD)
requirements would be liable for a failure to comply with these
requirements. Like other EPA fuels programs, the proposed rule provides
that a party who causes another party to violate a prohibition or fail
to comply with a requirement may be found liable for the violation.
EPAct amended the penalty and injunction provisions in section
211(d) of the Clean Air Act to apply to violations of the renewable
fuels requirements in section 211(o). Accordingly, under the proposed
rule, any person who violates any prohibition or requirement of the
RFS2 program may be subject to civil penalties of $32,500 for every day
of each such violation and the amount of economic benefit or savings
resulting from the violation. Under the proposed rule, a failure to
acquire sufficient RINs to meet a party's renewable fuels obligation
would constitute a separate day of violation for each day the violation
occurred during the annual averaging period.
As discussed above, the regulations would prohibit any party from
creating or transferring invalid RINs. These invalid RIN provisions
apply regardless of the good faith belief of a party that the RINs are
valid. These enforcement provisions are necessary to ensure the RFS2
program goals are not compromised by illegal conduct in the creation
and transfer of RINs.
As in other motor vehicle fuel credit programs, the regulations
would address the consequences if an obligated party was found to have
used invalid RINs to demonstrate compliance with its RVO.
[[Page 24971]]
In this situation, the obligated party that used the invalid RINs would
be required to deduct any invalid RINs from its compliance
calculations. Obligated parties would be liable for violating the
standard if the remaining number of valid RINs was insufficient to meet
its RVO, and the obligated party might be subject to monetary penalties
if it used invalid RINs in its compliance demonstration. In determining
what penalty is appropriate, if any, we would consider a number of
factors, including whether the obligated party did in fact procure
sufficient valid RINs to cover the deficit created by the invalid RINs,
and whether the purchaser was indeed a good faith purchaser based on an
investigation of the RIN transfer. A penalty might include both the
economic benefit of using invalid RINs and/or a gravity component.
Although an obligated party would be liable under our proposed
program for a violation if it used invalid RINs for compliance
purposes, we would normally look first to the generator or seller of
the invalid RINs both for payment of penalty and to procure sufficient
valid RINs to offset the invalid RINs. However, if, for example, that
party was out of business, then attention would turn to the obligated
party who would have to obtain sufficient valid RINs to offset the
invalid RINs.
We request comment on the need for additional prohibition and
liability provisions specific to the proposed RFS 2 program.
IV. What Other Program Changes Have We Considered?
In addition to the regulatory changes we are proposing today in
response to EISA that are designed to implement the provisions of RFS2,
there are a number of other changes to the RFS program that we are
considering. These changes would be designed to increase flexibility,
simplify compliance, or address RIN transfer issues that have arisen
since the start of the RFS1 program. We have also investigated impacts
on small businesses and are proposing approaches designed to address
the impacts of the program on them.
A. Attest Engagements
The purpose of an attest engagement is to receive third party
verification of information reported to EPA. An attest engagement,
which is similar to a financial audit, is conducted by a Certified
Public Accountant (CPA) or Certified Independent Auditor (CIA)
following agreed-upon procedures. Under the RFS1 program, an attest
engagement must be conducted annually. We propose to apply the same
provision to this proposed RFS2 rule. However, we seek comment on
whether there should be any flexibility provisions for those who own a
small number of RINs and what level of flexibility might be appropriate
(e.g., allowing those who own a small number of RINs to submit an
attest engagement every two years, rather than every year).
B. Small Refinery and Small Refiner Flexibilities
1. Small Refinery Temporary Exemption
CAA section 211(o)(8), enacted as part of EPAct, provides a
temporary exemption to small refineries (those refineries with a crude
throughput of no more than 75,000 barrels of crude per day, as defined
in section 211(o)(1)(K)) through December 31, 2010.\44\ Accordingly,
the RFS1 program regulations exempt gasoline produced by small
refineries from the renewable fuels standard (unless the exemption was
waived), see 40 CFR 80.1141. EISA did not alter the small refinery
exemption in any way. Therefore, we intend to retain this small
refinery temporary exemption in the RFS2 program without change.
Further, as discussed below in Section IV.B.2.c, we are proposing to
continue one of the hardship provisions for small refineries provided
at 40 CFR 80.1141(e).
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\44\ Small refineries are also allowed to waive this exemption.
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2. Small Refiner Flexibilities
As mentioned above, EPAct granted a temporary exemption from the
RFS program to small refineries through December 31, 2010. In the RFS1
final rule, we exercised our discretion under section 211(o)(3)(B) and
extended this temporary exemption to the few remaining small refiners
that met the Small Business Administration's (SBA) definition of a
small business (1,500 employees or less company-wide) but did not meet
the Congressional small refinery definition as noted above.
As explained in the discussion of our compliance with the
Regulatory Flexibility Act below in Section XII.C and in the Initial
Regulatory Flexibility Analysis in Chapter 7 of the draft RIA, we
considered the impacts of today's proposed regulations on small
businesses. Most of our analysis of small business impacts was
performed as a part of the work of the Small Business Advocacy Review
Panel (SBAR Panel, or ``the Panel'') convened by EPA, pursuant to the
Regulatory Flexibility Act as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). The Final Report of the
Panel is available in the docket for this proposed rule. For the SBREFA
process, we conducted outreach, fact-finding, and analysis of the
potential impacts of our regulations on small businesses.
During the SBREFA process, small refiners informed us that they
would need to rely heavily on RINs and/or make capital improvements to
comply with the RFS2 requirements. These refiners raised concerns about
the RIN program itself, uncertainty (with the required renewable fuel
volumes, RIN availability, and cost), and the desire for a RIN system
review access to RINs, and the difficulty in raising capital and
competing for engineering resources to make capital improvements.
During the Panel process, EPA raised a concern regarding provisions
for small refiners in the RFS2 rule; and this rule presents a very
different issue than the small refinery versus small refiner concept
from RFS1. This issue deals with whether or not EPA has the authority
to provide a subset of small refineries (those that are operated by
small refiners) with an extension of time that would be different from,
and more than, the temporary exemption specified by Congress in section
211(o)(9) for small refineries (temporary exemption through December
31, 2010, with the potential for extensions of the exemption beyond
this date if certain criteria are met.). In other words, the temporary
exemption specified by Congress provided relief for those small
refiners that are covered by the small refinery provision; EPA believes
that providing these refiners with an additional exemption different
from that provided by section 211(o)(9) may be inconsistent with the
intent of Congress. Congress spoke directly to the relief that EPA may
provide for small refineries, including those small refineries operated
by small refiners, and limited it to a blanket exemption through
December 31, 2010, with additional extensions if the criteria specified
by Congress were met.
The Panel recommended that EPA consider the issues raised by the
SERs and discussions had by the Panel itself, and that EPA should
consider comments on flexibility alternatives that would help to
mitigate negative impacts on small businesses to the extent allowable
by the Clean Air Act. A summary of further recommendations of the Panel
are discussed in Section XII.C of this preamble, and a full discussion
of the regulatory alternatives discussed and recommended by the Panel
can be found in the SBREFA Final Panel Report.
[[Page 24972]]
a. Extension of Existing RFS1 Temporary Exemption
As previously stated, the RFS1 program regulations provide small
refiners who operate small refineries, as well as those small refiners
who do not operate small refineries, with a temporary exemption from
the standards through December 31, 2010. Small refiner SERs suggested
that an additional temporary exemption for the RFS2 program would be
beneficial to them in meeting the RFS2 standards; and the Panel
recommended that EPA propose a delay in the effective date of the
standards until 2014 for small entities, to the maximum extent allowed
by the statute.
We have evaluated an additional temporary exemption for small
refiners for the required RFS2 standards, and we have also evaluated
such an exemption with respect to our concerns about our authority to
provide an extension of the temporary exemption for small refineries
that is different from that provided in CAA section 211(o)(9). As a
result, we believe that the limitations of the statute do not
necessarily allow us the discretion to provide an exemption for small
refiners only (i.e., small refiners but not small refineries) beyond
that provided in section 211(o)(9). However, it is important to
recognize that the 211(o)(9) small refinery provision does allow for
extensions beyond December 31, 2010, with two separate provisions
addressing extensions beyond 2010. These provisions are discussed below
in Section IV.B.2.c.
Therefore, we are proposing to continue the temporary exemption
finalized in RFS1--through December 31, 2010--for small refineries and
all qualified small refiners. We also request comment on the
interpretation of our authority under the CAA and the appropriateness
of providing an extension to small refiners only beyond that authorized
by section 211(o)(9).
b. Program Review
During the SBREFA process, the small refiner SERs also requested
that EPA perform an annual program review, to begin one year before
small refiners are required to comply with the program. We have slight
concerns that such a review could lead to some redundancy since EPA is
required to publish a notice of the applicable RFS standards in the
Federal Register annually, and this annual process will inevitably
include an evaluation of the projected availability of renewable fuels.
Nevertheless, some Panel members commented that they believe a program
review could be beneficial to small entities in providing them some
insight to the RFS program's progress and alleviate some uncertainty
regarding the RIN system. As we will be publishing a Federal Register
notice annually, the Panel recommended that we include an update of RIN
system progress (e.g., RIN trading, publicly-available information RIN
availability, etc.) in this annual notice.
We propose to include elements of RIN system progress--such as RIN
trading and availability--in the annual Federal Register RFS2 standards
notice. We also invite comment on additional elements to include in
this review.
c. Extensions of the Temporary Exemption Based on Disproportionate
Economic Hardship
As noted above, there are two provisions in section 211(o)(9) that
allow for an extension of the temporary exemption beyond December 31,
2010. One involves a study by the Department of Energy (DOE) concerning
whether compliance with the renewable fuel requirements would impose
disproportionate economic hardship on small refineries, and would grant
an extension of at least two years for a small refinery that DOE
determines would be subject to such disproportionate hardship. Another
provision authorizes EPA to grant an extension for a small refinery
based upon disproportionate economic hardship, on a case-by-case basis.
We believe that these avenues of relief can and should be fully
explored by small refiners who are covered by the small refinery
provision. In addition, we believe that it is appropriate to consider
allowing petitions to EPA for an extension of the temporary exemption
based on disproportionate economic hardship for those small refiners
who are not covered by the small refinery provision (again, per our
discretion under section 211(o)(3)(B)); this would ensure that all
small refiners have the same relief available to them as small
refineries do. Thus, we are proposing a hardship provision for small
refineries in the RFS2 program, that any small refinery may apply for a
case-by-case hardship at any time on the basis of disproportionate
economic hardship per CAA section 211(o)(9)(B). While EISA stated (per
section 211(o)(9)(A)(ii)(I)) that the small refinery temporary
exemption shall be extended for at least two years for any small
refinery that the DOE small refinery study determines would face
disproportionate economic hardship in meeting the requirements of the
RFS2 program, we are not proposing this hardship provision given the
outcome of the DOE small refinery study (as discussed below).
In the small refinery study, ``EPACT 2005 Section 1501 Small
Refineries Exemption Study'', DOE's finding was that there is no reason
to believe that any small refinery would be disproportionately harmed
by inclusion in the proposed RFS2 program. This finding was based on
the fact that there appeared to be no shortage of RINs available under
RFS1, and EISA has provided flexibility through waiver authority (per
section 211(o)(7)). Further, in the case of the cellulosic biofuel
standard, cellulosic biofuel allowances can be provided from EPA at
prices established in EISA (see proposed regulation section 80.1455).
DOE thus determined that no small refinery would be subject to
disproportionate economic hardship under the proposed RFS2 program, and
that the small refinery exemption should not be extended beyond
December 31, 2010. DOE noted in the study that, if circumstances were
to change and/or the RIN market were to become non-competitive or
illiquid, individual small refineries have the ability to petition EPA
for an extension of their small refinery exemption (as proposed at
draft regulation section 80.1441). We note that the findings of DOE's
small refinery study, and a consideration of EPA's ongoing review of
the functioning of the RIN market, could factor into the basis for
approval of such a hardship request.
We are also proposing a case-by-case hardship provision for those
small refiners that do not operate small refineries, at draft
regulation section 80.1442(h), using our discretion under CAA section
211(o)(3)(B). This proposed provision would allow those small refiners
that do not operate small refineries to apply for the same kind of
extension as a small refinery. In evaluating applications for this
proposed hardship provision, it was recommended by the SBAR Panel that
EPA take into consideration information gathered from annual reports
and RIN system progress updates.
d. Phase-in
The small refiner SERs suggested that a phase-in of the obligations
applicable to small refiners would be beneficial for compliance, such
that small refiners would comply by gradually meeting the standards on
an incremental basis over a period of time, after which point they
would comply fully with the RFS2 standards, however we have concerns
about our authority under the statute to allow for such a phase-in of
the standards. CAA section 211(o)(3)(B) states that the renewable fuel
obligation
[[Page 24973]]
shall ``consist of a single applicable percentage that applies to all
categories of persons specified'' as obligated parties. This kind of
phase-in approach would result in different applicable percentages
being applied to different obligated parties. Further, as discussed
above, such a phase-in approach would provide more relief to small
refineries operated by small refiners than that provided under the
small refinery provision. We do not believe that we can use our
discretion under the statute to allow for such a provision; however we
invite comment on the concept of a phase-in provision for all small
refiners.
e. RIN-Related Flexibilities
The small refiner SERs requested that the proposed rule contain
provisions for small refiners related to the RIN system, such as
flexibilities in the RIN rollover cap percentage and allowing all small
refiners to use RINs interchangeably. Currently in the RFS program, up
to 20% of a previous year's RINs may be ``rolled over'' and used for
compliance in the following year. A provision to allow for
flexibilities in the rollover cap could include a higher RIN rollover
cap for small refiners for some period of time or for at least some of
the four standards. While the rollover cap is the means through which
we are implementing the limited credit lifetime provisions in section
211(o) of the CAA, and therefore cannot simply be eliminated, the
magnitude of the cap can be modified to some extent. Thus, there could
be an opportunity to provide appropriate flexibility in this area.
However, given the results of the DOE small refinery study, we do not
believe it would be appropriate to propose a change to the RIN rollover
cap for small refiners today. However, we request comment on the
concept of increasing the RIN rollover cap percentage for small
refiners. We also request comment on an appropriate level of that
percentage. For example, would a rollover cap of 50% for small refiners
be appropriate? Or, would an intermediate value between 20% and 50%,
such as 35%, be more appropriate?
The Panel recommended that we take comment on allowing RINs to be
used interchangeably for small refiners, but not propose this concept
because under this approach small refiners would arguably be subject to
a different applicable percentage than other obligated parties.
However, this concept fails to require the four different standards
mandated by Congress (e.g., conventional biofuel could not be used
instead of cellulosic biofuel or biomass-based diesel), and is not
consistent with section 211(o) of the Clean Air Act. Thus, we are not
proposing this provision in this action, however we invite comment on
such an approach for small refiners.
C. Other Flexibilities
1. Upward Delegation of RIN-Separating Responsibilities
Since the start of the RFS1 program on September 1, 2007, there
have been a number of instances in which a party who receives RINs with
a volume of renewable fuel is required to either separate or retire
those RINs, but views the recordkeeping and reporting requirements
under the RFS program as an unnecessary burden. Such circumstances
typically might involve a renewable fuel blender, a party that uses
renewable fuel in its neat form, or a party that uses renewable fuel in
a non-highway application and is therefore required to retire the RINs
(under RFS1) associated with the volume. In some of these cases, the
affected party may purchase and/or use only small volumes of renewable
fuel and, absent the RFS program, would be subject to few if any other
EPA regulations governing fuels.
This situation will become more prevalent with the RFS2 program, as
EISA added diesel fuel to the RFS program. With the RFS1 rule, small
blenders (generally farmers and other parties that use nonroad diesel
fuel) blending small amounts of biodiesel were not covered under the
rule as EPAct mandated renewable fuel blending for highway use only.
EISA mandates certain amounts of renewable fuels to be blended into
transportation fuels--which includes nonroad diesel fuel. Thus, parties
that were not regulated under the RFS1 rule who only blend a small
amount of renewable fuel (and, as mentioned above, are generally not
subject to many of the EPA fuels regulations) would now be regulated by
the program.
Consequently, we believe it may be appropriate, and thus we are
proposing today, to permit blenders who only blend a small amount of
renewable fuel to allow the party directly upstream to separate RINs on
their behalf. Such a provision would be consistent with the fact that
the RFS1 program already allows marketers of renewable fuels to assign
more RINs to some of their sold product and no RINs to the rest of
their sold product. We believe that this provision would eliminate
undue burden on small parties who would otherwise not be regulated by
this program. We are proposing that this provision apply to small
blenders who blend and trade less than 125,000 total gallons of
renewable fuel per year. We also request comment on whether or not this
threshold is appropriate.
We envision that such a provision would be available to any blender
who must separate RINs from a volume of renewable fuel under Sec.
80.1429(b)(2). We also request comment on appropriate documentation to
authorize this upward delegation. This could be something such as a
document given to the supplier identifying the RIN separation that the
supplier would perform. The document could include sufficient
information to precisely identify the conditions of the authorization,
such as the volume of renewable fuel in question and the number of RINs
assigned to that volume. By necessity the document would need to be
signed by both parties, and copies retained as records by both parties,
since the supplier would then be responsible for these actions. The
supplier would then be allowed to retain ownership of RINs assigned to
a volume of renewable fuel when that volume is transferred, under the
condition that the RINs be separated or retired concurrently with the
transfer of the volume. We are proposing an annual authorization that
would apply to all volumes of renewable fuel transferred between two
parties for a given year (i.e., the two parties would enter into a
contract stating that the supplier has RIN-separation responsibilities
for all transferred volumes).
We are proposing this provision solely for the case of blenders who
blend and trade less than 125,000 total gallons of renewable fuel per
year. A company that blends 100,000 gallons and trades 100,000 gallons
would not be able to use this provision. However, we request comment on
whether authorization to delegate RIN-separation responsibilities
should also be allowed for other parties as well.
2. Small Producer Exemption
Under the RFS1 program, parties who produce or import less than
10,000 gallons of renewable fuel in a year are not required to generate
RINs for that volume, and are not required to register with the EPA if
they do not take ownership of RINs generated by other parties. We
propose to maintain this exemption under the RFS2 rule. However, we
request comment on whether the 10,000 gallon threshold should be higher
given that the total volume of renewable fuel mandated by EISA is
considerably higher than that required by the RFS1 program, or
conversely whether it should be lower given that the biomass-based
diesel standard is considerably lower than the
[[Page 24974]]
mandated volume for total renewable fuel.
D. 20% Rollover Cap
EISA does not change the language in CAA section 211(o)(5) stating
that renewable fuel credits must be valid for showing compliance for 12
months as of the date of generation. As discussed in the RFS1 final
rulemaking, we interpreted the statute such that credits would
represent renewable fuel volumes in excess of what an obligated party
needs to meet their annual compliance obligation. Given that the
renewable fuel standard is an annual standard, obligated parties
determine compliance shortly after the end of the year, and credits
would be identified at that time. In the context of our RIN-based
program, we have accomplished the statute's objective by allowing RINs
to be used to show compliance for the year in which the renewable fuel
was produced and its associated RIN first generated, or for the
following year. RINs not used for compliance purposes in the year in
which they were generated will by definition be in excess of the RINs
needed by obligated parties in that year, making excess RINs equivalent
to the credits referred to in section 211(o)(5). Excess RINs are valid
for compliance purposes in the year following the one in which they
initially came into existence. RINs not used within their valid life
will thereafter cease to be valid for compliance purposes.
In the RFS1 final rulemaking, we also discussed the potential
``rollover'' of excess RINs over multiple years. This can occur in
situations wherein the total number of RINs generated each year for a
number of years in a row exceeds the number of RINs required under the
RFS program for those years. The excess RINs generated in one year
could be used to show compliance in the next year, leading to the
generation of new excess RINs in the next year, causing the total
number of excess RINs in the market to accumulate over multiple years
despite the limit on RIN life. The rollover issue could in some
circumstances undermine the ability of a limit on credit life to
guarantee an ongoing market for renewable fuels.
To implement the Act's restriction on the life of credits and
address the rollover issue, the RFS1 final rulemaking implemented a 20%
cap on the amount of an obligated party's RVO that can be met using
previous-year RINs. Thus each obligated party is required to use
current-year RINs to meet at least 80% of its RVO, with a maximum of
20% being derived from previous-year RINs. Any previous-year RINs that
an obligated party may have that are in excess of the 20% cap can be
traded to other obligated parties that need them. If the previous-year
RINs in excess of the 20% cap are not used by any obligated party for
compliance, they will thereafter cease to be valid for compliance
purposes.
EISA does not modify the statutory provisions regarding credit
life, and the volume changes by EISA also do not change at least the
possibility of large rollovers of RINs for individual obligated
parties. Therefore, we propose to maintain the regulatory requirement
for a 20% rollover cap under the new RFS2 program. However, under RFS2
obligated parties will have four RVOs instead of one. As a result, we
are proposing that the 20% rollover cap would apply separately to all
four RVOs. We do not believe it would be appropriate to apply the
rollover cap to only the RVO representing total renewable fuel, leaving
the other three RVOs with no rollover cap. Doing so would allow all
previous-year RINs used for compliance to be those with a D code of 4,
and this in turn would allow an obligated party to meet one of the
nested standards, such as that for biomass-based diesel, using more
than 20% previous-year RINs. This could result in significant rollover
of RINs with a D code of 2, representing biomass-based diesel, and the
valid life of these RINs would have no meaning in this case.
Some obligated parties have suggested that the rollover cap should
be raised to a value higher than 20%, citing the need for greater
flexibility in the face of significantly higher volume requirements.
However, we believe that a higher value could create disruptions in the
RIN market as parties with excess RINs would have a greater incentive
to hold onto them rather than sell them. This would especially be a
concern in years where the volume of renewable fuel available in the
market is very close to the RFS requirements. Nevertheless, we request
comment on whether the 20% rollover cap should be raised to a higher
value.
As described in Section III.G.4, some parties have also suggested
that the rollover cap should be lowered to a value lower than 20%, such
as 10%. In the event of concerns about the availability of RINs, a
lower rollover cap would provide a greater incentive for parties with
excess RINs to sell them rather than hold onto them. However, a lower
rollover cap would also reduce flexibility for many obligated parties.
While we are not proposing it in today's notice, we request comment on
it.
E. Concept for EPA Moderated Transaction System
1. The Need for an EPA Moderated Transaction System
In implementing RFS1, we found that the 38-digit standardized RINs
have proven confusing to many parties in the distribution chain.
Parties have made various errors in generating and using RINs. For
example, we have seen errors wherein parties have transposed digits
within the RIN. We have seen parties creating alphanumeric RINs,
despite the fact that RINs are supposed to consist of all numbers. We
have also seen incorrect numbering of volume start and end codes.
Once an error is made within a RIN, the error propagates throughout
the distribution system. Correcting an error can require significant
time and resources and involve many steps. Not only must reports to EPA
be corrected, underlying records and reports reflecting RIN
transactions must also be located and corrected to reflect discovery of
an error. Because reporting related to RIN transactions under RFS1 is
only on a quarterly basis, a RIN error may exist for several months
before being discovered.
Incorrect RINs are invalid RINs. If parties in the distribution
system cannot track down and correct the error made by one of them in a
timely manner, then all downstream parties that trade the invalid RIN
will be in violation. Because RINs are the basic unit of compliance for
the RFS1 program, it is important that parties have confidence when
generating and using them.
All parties in the RFS1 and the proposed RFS2 regulated community
use RINs. These parties include producers of renewable fuels, obligated
parties, exporters, and other owners of RINS, typically marketers of
renewable fuels and blenders. (Anyone can own RINs, but those who do
would be subject to registration, recordkeeping, reporting, and attest
engagement requirements described in this preamble.). Currently under
RFS1, all RINs are used to comply with a single standard, and in 2013
an additional cellulosic standard would have been added. Under this
proposed rule, there are four standards, and RINs must be generated to
identify four types of renewable fuels: cellulosic biofuel, biomass-
based diesel, other advanced biofuels, and other renewable fuels (e.g.,
corn ethanol). (For a more detailed discussion of RINs, see Section
III.A of this preamble.) In the proposed EPA Moderated Transaction
System (EMTS), the four types of RINs will be managed through four
types of account.
[[Page 24975]]
Based upon problems we observed with the use of RINs under RFS1,
and considering that we will now have a more complex system including
four standards instead of just one, we believe that the best way to
screen RINs and conduct RIN-based transactions is through EMTS.
This section describes the proposed EMTS and options for
implementing it. By implementing EMTS, we believe that we would be able
to greatly reduce RIN-related errors and efficiently and accurately
manage the universe of RINs. There are two aspects to our proposal for
EMTS. The first aspect focuses upon creating four, generic types of RIN
account. The second aspect focuses upon actually developing a ``real
time'' environment for handling RIN trades.
2. How EMTS Would Work
EMTS would be a closed, EPA-managed system that provides a
mechanism for screening RINs as well as a structured environment for
conducting RIN transactions. ``Screening'' RINs will mean that parties
would have much greater confidence that the RINs they handle are
genuine. Although screening cannot remove all human error, we believe
it can remove most of it.
We propose that screening and assignment of RINs be made at the
logical point, i.e., the point when RINs are generated through
production or importation of renewable fuel. A renewable producer would
electronically submit, in ``real time,'' a batch report for the volume
of renewable fuel produced or imported, as well as a list of the RINs
generated and assigned. EMTS would automatically screen each batch and
either reject the RINs or permit them to pass into the transaction
system, into the RIN generator's account, as one of the four types of
RINs. Note that under RFS1, RIN generation (batch) and RIN transaction
reports are submitted quarterly. Batch reports are submitted by
producers and importers quarterly and reflect how they generated and
assigned RINS to batches. RIN transaction reports are submitted by all
parties who engage in RIN transactions, including buying or selling
RINs. Under this proposed approach for RFS2, these batch reports and
RIN transaction reports would be submitted monthly for calendar year
2010. However, once EMTS is implemented in calendar year 2011, these
separate periodic reports may no longer be necessary. Instead the
information would be submitted as RINs are generated and assigned
within EMTS.
Under RFS1, the producer or importer list RINs they generate and
assign via the batch report. EPA, in turn, uses the batch report data
to verify RINs generated and transacted. The report is submitted
quarterly. Under RFS1, the purpose of the RIN transaction report is to
document RIN transactions and to document that RINs have been sold or
transferred from party to party in the distribution system. This report
is also submitted quarterly. The RIN transaction report includes the
following information in this report: its name, its EPA company
registration number, and in some cases (where compliance is on a
facility basis), its EPA facility identification number. For the
quarterly reporting period, the reporting party indicates the
transaction type (RIN purchase, RIN sale, expired RIN, or retired RIN),
and the date of the transaction. For a RIN purchase or sale, the
transaction report includes the trading partner's name and the trading
partner's EPA company registration number. There is also information
that may have to be submitted in the event a reporting party must
report a RIN that has been retired (e.g., when a RIN has become invalid
due to the spillage of the associated volume of renewable fuel). As
discussed above, the shortcoming of these reports is that they are only
submitted quarterly. RIN errors that affect compliance may not be
discovered for many months because of the relative infrequency of
reporting transactions to EPA. EMTS will assume the functionality of
batch reporting and transaction reporting used by regulated parties,
allowing EPA to better screen RINs and reduce or eliminate generation
and transaction errors.
Under the RFS2 program, we are proposing that batch reports
submitted by producers and importers and RIN transaction reports be
submitted monthly rather than quarterly in the first year of the
program (i.e., calendar year 2010). During 2010, we will be finishing
development and testing of the EMTS. In order to minimize the hardship
that undiscovered, invalid RINs may cause, we propose and seek comment
on increasing the frequency of reporting and our own review of reports
in order to assist the regulated community with compliance. As we
develop EMTS through calendar year 2010, we intend to invite and
encourage interested reporting parties to ``opt in'' to EMTS. This will
serve a two-fold purpose: regulated parties may opt to gain familiarity
EMTS before it becomes fully operational and we may have actual
customers with which to test EMTS prior to it becoming fully
operational. We believe that permitting interested parties to ``opt
in'' will result in a better EMTS for all.
In the second year of the program (i.e., calendar year 2011 and
forward), we anticipate fully implementing the proposed EMTS and
receiving the data contained in batch and RIN transaction reports in
relatively ``real time'' (i.e., as transactions occur). We propose that
``real time'' be construed as within three (3) business days of a
reportable event (e.g., generation and assignment of RINs, transfer of
RINs).
Parties who use EMTS would have to register with EPA in accordance
with the proposed RFS2 registration program described in Section III.C
of this preamble. They would also have to create an account (i.e.,
register) via EPA's Central Data Exchange (CDX), as we envision
managing EMTS via CDX. CDX is a secure and central portal through which
parties may submit compliance reports. We propose that parties must
establish an account with EMTS by October 1, 2010 or 60 days prior to
engaging in any transaction involving RINs, whichever is later. As
discussed above, the actual items of information covered by reporting
under RFS2 are nearly identical to those reported under RFS1.
Once registration occurs with EMTS, individual RIN accounts would
be established and the system would manage the accounts for each
individual party. The RIN accounts would correspond to the four broad
types of renewable fuel. RIN accounts would be established for
cellulosic biofuel, biomass-based diesel, other advanced biofuels, and
other renewable fuels (including corn ethanol). One big advantage of
RIN accounts is that the system would make available generic accounts
for transactions involving RINs of similar type. The unique
identification of the RIN would exist within EMTS, but parties engaging
in RIN transactions would no longer have to worry about incorrectly
recording or using 38-digit RIN numbers. As with RFS1, there is no
``good faith'' provision to RIN ownership. An underlying principle of
RIN ownership is still one of ``buyer beware'' and RINs may be
prohibited from use at any time if they are found to be invalid.
Because of the ``buyer beware'' aspect, we intend to offer the option
for a buyer to accept or reject RINs from specific RIN generators or
from classes of RIN generators. Also, we propose to collect information
about the price associated with RINs traded. This information is not
collected under RFS1, but we believe this information has great
programmatic value to EPA because it may help us to anticipate and
[[Page 24976]]
appropriately react to market disruptions and other compliance
challenges, assess and develop responses to potential waivers, and
assist in setting future renewable standards. We believe that highly
summarized price information (e.g., the average price of RINs traded
nationwide) may be valuable to regulated parties, as well, and may help
them to anticipate and avoid market disruptions.
The following is an example of how a RIN transaction might occur in
the proposed EMTS model:
1. Seller logs into EMTS and posts his sale of 10,000 RINs to
Buyer. For this example, assume the RINs were generated in 2008 and
were assigned to 10,000 gallons of ``other renewable fuel'' (corn
ethanol). Seller's RIN account for ``other renewable fuel'' is
automatically reduced by 10,000 with the posting of his sale to Buyer.
Buyer receives automatic notification of the pending transaction.
2. Buyer logs into EMTS. She sees the sale transaction pending.
Assuming it is correct, she accepts it. Upon her acceptance, her RIN
account for ``other renewable fuel'' (corn ethanol) is automatically
increased by 10,000 2008 assigned RINs.
3. After Seller has posted his sale and Buyer has accepted it, EMTS
automatically notifies both Buyer and Seller that the transaction has
been fully completed.
Under EMTS as we are proposing it, the seller would always have to
initiate any transaction. The seller's account is reduced when he posts
his sale. The buyer must acknowledge the sale in order to have the RINs
transferred to her account. Transactions would always be limited to
available RINs. Notification would automatically be sent to both the
buyer and the seller upon completion of the transaction. EPA proposes
to consider any sale or transfer as complete upon acknowledgement by
the buyer.
We propose that RINs and the parameters of RIN generation (e.g.,
year) be considered public information. We also propose that summary
RIN price information, such as average price of all RINs in a broad
geographic area (such as a state, region, or nationwide) be considered
public information. This summary price information would be aggregated
from transactions conducted within EMTS, but would not be identified
with individual companies or particular transactions that have
occurred. Because we believe information about RIN pricing in general
will be useful to regulated parties, we are proposing to make this
information available to them. We propose that the actual transactions
between parties and that individual company account information may be
claimed as confidential business information (CBI) by the parties to
that transaction. EPA would treat any information submitted that is
covered by a CBI claim in accordance with the procedures at 40 CFR Part
2 and applicable Agency policies and guidelines for the handling of
claimed CBI.
3. Implementation of EMTS
We anticipate that implementing EMTS will take until January 1,
2011, although we are proposing that the RFS2 program be effective on
January 1, 2010. We anticipate that development of EMTS will require
significant time and effort and that a delayed effective date may
permit better pre-testing with interested regulated parties. We propose
to permit regulated parties who are willing to participate in EMTS
early to voluntarily opt-in to the system before January 1, 2011. The
actual date for these parties' opt-in will depend upon the actual
timeline for development of EMTS. We encourage comments from interested
parties as to how we might best make use of the development period and
the proposed opportunity for willing and interested parties to ``opt
in'' early.
Under our proposed scenario, for the 2010 compliance year,
recordkeeping and reporting would be analogous to RFS1, although
registration would be enhanced in accordance with the discussion in
Section III.C of this preamble and recordkeeping and reporting would
reflect the four types of RIN described above. In order to avoid
propagation of RIN-related errors and to prevent errors from going too
long without being detected, we believe it is necessary to increase the
frequency of batch reporting and RIN transaction reporting to monthly
rather than quarterly during 2010.
EPA will implement the EMTS during the first year of the RFS2
program. RINs generated under the RFS1 regulations will continue to be
traded and reported using the current processes. RINs would still have
unique identifying information, but EMTS will allow transactions to
take place on a generic basis having the system track the specific
unique identifiers. We believe that EMTS will virtually eliminate
errors related to tracking and using individual RINs. Parties will be
required to submit RIN transactions by specifying RIN year, RIN
assignment, RIN fuel type, and any other reporting requirement
specified by the administrator.
Implementation of EMTS should save considerable time and resources
for both industry and EPA. This is most evident considering that the
proposed system virtually eliminates multiple sources of administrative
errors, resulting in a reduction in costs and effort expended to
correct and regenerate product transfer documents, documentation and
recordkeeping, and resubmitting reports to EPA. We anticipate that a
fully functioning EMTS will result in fewer reports and easier
reporting for industry, and fewer reports requiring processing by EPA.
Industry will need to spend less time and effort verifying the validity
of the RINs they procure and allowing them to procure them on the open
market with confidence. EPA will need to spend less time tracking down
the responsible parties for invalid RINs. This is possible because EMTS
will remove management of the 38-digit RIN from the hands of the
reporting community. At the same time, EPA and the reporting community
will be working with a standardized system, reducing stresses and
development costs on IT systems.
In summary, the advantage to implementing EMTS is that parties may
engage in RIN transactions with a high degree of confidence. Errors
would be virtually eliminated. Everyone engaging in RIN transactions
would have a simplified environment in which to work which should
minimize the level of resources needed for implementation. However, the
one unavoidable disadvantage that we foresee is that parties would have
to switch to a new and different reporting system in the second year of
the RFS2 program. Some errors may still occur in by parties who
continue to generate and use the 38-digit RINs during 2010. As
discussed above, we propose to increase the frequency of batch and RIN
transaction reporting to monthly for 2010, in order that we may help
parties discover errors and correct them before they become violations.
We also propose to permit parties to voluntarily ``opt in'' to using
EMTS while it is still in development in order to ease the transition.
We invite comment from all interested parties as to how we may best
assist regulated parties in transitioning from the ``old'' RFS1 method
of handing RINs to the ``new,'' proposed RFS2 EMTS method on January 1,
2011.
We also invite comment on whether, in the event the RFS2 start date
is delayed, EPA should nevertheless allow a one-year period during
which use of EMTS is optional, or if EPA should begin the program at
the inception of the delayed RFS2 program if EMTS is fully operational
at that time.
[[Page 24977]]
F. Retail Dispenser Labelling for Gasoline With Greater Than 10 Percent
Ethanol
Fuel retailers expressed concern that the magnitude of the price
discount for E85 relative to E10 that would be necessary to facilitate
sufficient use of E85 would encourage widespread misfueling of non-flex
fuel vehicles. Today's proposal contains labeling requirements for
pumps that dispense blends that contain greater than 10% ethanol which
state that the use in non-flex fuel vehicles is prohibited and may
cause damage to the vehicle.\45\ We anticipate that the industry would
also conduct public information activities to alert customers who may
not have yet become accustomed to seeing E85 at retail to avoid using
E85 in their non-flex-fuel vehicles. Uniquely colored/labeled nozzle
handles may also be useful in helping to prevent accidental cases of
misfueling. We believe that in most cases the warnings that the use of
E85 in non-flex fuel vehicles is illegal, can damage the vehicle, and
can void vehicle manufacturer warranties may be a sufficient
disincentive to prevent intentional misfueling. In cases where
intentional misfueling may occasionally take place, the party is likely
to experience drivability problems and thus would not repeat the act.
---------------------------------------------------------------------------
\45\ See section 80.1469 in the proposed regulatory text.
---------------------------------------------------------------------------
Today's proposal does not contain requirements that E85 refueling
hardware be configured to prevent the introduction of E85 into non-
flex-fuel vehicles. It is unclear how such an approach could be
implemented to allow the approximately 6 million flex-fuel vehicles on
the road today to continue to be fueled with E85 without modification
to their filler neck hardware.\46\ In any event, we do not believe that
unique E85 nozzles are necessary.
---------------------------------------------------------------------------
\46\ An E85 nozzle design and corresponding flex-fuel vehicle
filler design that would prevent the introduction of E85 into non-
flex-fuel vehicles while allowing flex fuel vehicles to be fueled
with E10 as well as E85 would also prevent the introduction of E85
into current flex-fuel vehicles since there is currently no
difference in nozzle/filler neck hardware between flex-fuel and non-
flex-fuel vehicles.
---------------------------------------------------------------------------
We request comment on whether the proposed labeling requirements
and voluntary measures such as those described above would provide
sufficient warning to fuel retail customers not to refuel non-flex-fuel
vehicles with E85. To the extent that other measures to prevent
misfueling are thought to be necessary, comment is requested on the
specific nature of such measures and the associated potential costs and
benefits. One additional potential measure to prevent misfueling would
be for cards to be issued to flex fuel vehicle owners and for all E85
dispensers to be equipped with card readers that would allow E85 to be
dispensed only to card holders.
V. Assessment of Renewable Fuel Production Capacity and Use
To assess the impacts of this rule, there must be a clear
understanding of the kind of renewable fuels that could be used, the
types and locations of their feedstocks, the fuel volumes that could be
produced by a given feedstock, and any challenges associated with their
use. This section provides this assessment of the potential feedstocks
and renewable fuels that may be used to meet the Energy Independence
and Security Act (EISA) and the rationale behind our projections of
various fuel types to represent the control case for analysis purposes.
Definitional issues regarding the four types of renewable fuel required
under EISA are discussed in Section III.B of this preamble.
A. Summary of Projected Volumes
EISA mandates the use of increasing volumes of renewable fuel. To
assess the impacts of this increase in renewable fuel volume from
business-as-usual (what is likely to have occurred without EISA), we
have established a reference and control case from which subsequent
analyses are based. The reference case is essentially a projection of
renewable fuel volumes without the enactment of EISA. The control case
is a projection of the volumes and types of renewable fuel that might
be used to comply with the EISA volume mandates. Both the reference and
control cases are discussed in further detail below.
1. Reference Case
Our reference case renewable fuel volumes are based on the Energy
Information Administration's (EIA) Annual Energy Outlook (AEO) 2007
reference case projections. The AEO 2007 presents long-term projections
of energy supply, demand, and prices through 2030 based on results from
EIA's National Energy Modeling System (NEMS). EIA's analysis focuses
primarily on a reference case (which we use as our reference case),
lower and higher economic growth cases, and lower and higher energy
price cases. AEO 2007 projections generally are based on Federal,
State, and local laws and regulations in effect on or before October
31, 2006.\47\ The potential impacts of pending or proposed legislation,
regulations, and standards are not reflected in the projections. While
AEO 2007 is not as up-to-date as AEO 2008 (or the recently released AEO
2009), we chose to use AEO 2007 because AEO 2008 already includes the
impact of increased renewable fuel volumes under EISA as well as fuel
economy improvements under CAFE, whereas AEO 2007 did not. Table V.A.1-
1 summarizes the fuel types and volumes for the years 2009-2022 as
taken from AEO 2007. For our air quality analysis we also considered a
reference case assuming the mandated renewable fuel volumes under the
Renewable Fuel Standard Program from the Energy Policy Act of 2005
(EPAct). Refer to Section VII for further details.
---------------------------------------------------------------------------
\47\ EIA. Annual Energy Outlook 2007 with Projections to 2030.
http://www.eia.doe.gov/oiaf/archive/aeo07/index.html. Accessed
February 2008.
Table V.A.1-1--AEO 2007 Reference Case Projected Renewable Fuel Volumes
[billion gallons]
----------------------------------------------------------------------------------------------------------------
Advanced biofuel Non-advanced
------------------------------------------------ biofuel
Cellulosic Biomass-based Other advanced ---------------- Total
Year biofuel diesel\a\ biofuel renewable
------------------------------------------------ fuel
Cellulosic FAME Imported Corn ethanol
ethanol biodiesel\b\ ethanol
----------------------------------------------------------------------------------------------------------------
2009............................ 0.07 0.32 0.50 9.44 10.33
2010............................ 0.12 0.32 0.29 10.49 11.22
2011............................ 0.19 0.33 0.16 10.69 11.37
2012............................ 0.25 0.33 0.18 10.81 11.57
[[Page 24978]]
2013............................ 0.25 0.33 0.19 10.93 11.70
2014............................ 0.25 0.23 0.20 11.01 11.69
2015............................ 0.25 0.25 0.39 11.10 11.99
2016............................ 0.25 0.35 0.51 11.16 12.27
2017............................ 0.25 0.36 0.53 11.30 12.44
2018............................ 0.25 0.36 0.54 11.49 12.64
2019............................ 0.25 0.37 0.58 11.69 12.89
2020............................ 0.25 0.37 0.60 11.83 13.05
2021............................ 0.25 0.38 0.63 12.07 13.33
2022............................ 0.25 0.38 0.64 12.29 13.56
----------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. AEO
2007 only projects FAME biodiesel volumes.
\b\ Fatty acid methyl ester (FAME) biodiesel.
2. Control Case for Analyses
Our assessment of the renewable fuel volumes required to meet EISA
necessitates establishing a primary set of fuel types and volumes on
which to base our assessment of the impacts of the new standards. EISA
contains four broad categories: cellulosic biofuel, biomass-based
diesel, total advanced biofuel, and total renewable fuel. As these
categories could be met with a wide variety of fuel choices, in order
to assess the impacts of the rule, we projected a set of reasonable
renewable fuel volumes based on our interpretation at the time we began
our analysis of likely fuels that could come to market.
Although actual volumes and feedstocks may be different, we believe
the projections made for our control case are within the range of
reasonable predictions and allow for an assessment of the potential
impacts of the RFS2 standards. Table V.A.2-1 summarizes the fuel types
used for the control case and their corresponding volumes for the years
2009-2022.
Table V.A. 2-1--Control Case Projected Renewable Fuel Volumes
[billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Advanced biofuel Non-
----------------------------------------------------------------- Advanced
Cellulosic Biomass-based diesel \a\ Other advanced biofuel Biofuel
biofuel ----------------------------------------------------------------- Total
Year ------------- Non-co- Co- renewable
FAME \b\ processed processed Imported Corn fuel
Cellulosic biodiesel renewable renewable ethanol ethanol
ethanol diesel diesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
2009......................................................... 0.00 0.50 0.00 0.00 0.50 9.85 10.85
2010......................................................... 0.10 0.64 0.01 0.01 0.29 11.55 12.60
2011......................................................... 0.25 0.77 0.03 0.03 0.16 12.29 13.53
2012......................................................... 0.50 0.96 0.04 0.04 0.18 12.94 14.66
2013......................................................... 1.00 0.94 0.06 0.06 0.19 13.75 16.00
2014......................................................... 1.75 0.93 0.07 0.07 0.36 14.40 17.58
2015......................................................... 3.00 0.91 0.09 0.09 0.83 15.00 19.92
2016......................................................... 4.25 0.90 0.10 0.10 1.31 15.00 21.66
2017......................................................... 5.50 0.88 0.12 0.12 1.78 15.00 23.40
2018......................................................... 7.00 0.87 0.13 0.13 2.25 15.00 25.38
2019......................................................... 8.50 0.85 0.15 0.15 2.72 15.00 27.37
2020......................................................... 10.50 0.84 0.16 0.16 2.70 15.00 29.36
2021......................................................... 13.50 0.83 0.17 0.17 2.67 15.00 32.34
2022......................................................... 16.00 0.81 0.19 0.19 3.14 15.00 35.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Fatty acid methyl ester (FAME) biodiesel.
We needed to make this projection soon after EISA was signed to
allow sufficient time to conduct our long lead-time analyses. As a
result, we used the same ethanol-equivalence basis for these
projections as was used in the RFS1 rulemaking. However, as described
in Section III.D.1, we are also co-proposing that volumes of renewable
fuel be counted on a straight gallon-for-gallon basis under RFS2, such
that all Equivalence Values would be 1.0. The net effect of these two
approaches to Equivalence Values on projected volumes is very small;
instead of 36 billion gallons of renewable fuel in 2022, our control
case includes 35.3 billion gallons. We do not believe that
[[Page 24979]]
this difference will substantively affect the analyses that are based
on our projected control case volumes.
The following subsections detail our rationale for projecting the
amount and type of fuels needed to meet EISA as shown in Table V.A.2-1.
For cellulosic biofuel we have assumed that the entire volume will be
domestically produced cellulosic ethanol. Biomass-based diesel is
assumed to be comprised of a majority of fatty-acid methyl ester (FAME)
biodiesel and a smaller portion of non-co-processed renewable diesel.
The portion of the advanced biofuel category not met from cellulosic
biofuel and biomass-based diesel is assumed to come mainly from
imported (sugarcane) ethanol with a smaller amount from co-processed
renewable diesel. The total renewable fuel volume not required to be
comprised of advanced biofuels is assumed to be met with corn ethanol.
In addition, the following subsections also describe other fuels
that have the potential to contribute to meeting EISA, but because of
their uncertainty of use, or because their use likely might be
negligible we have chosen to not assume any use for our analysis.
Examples of these types of renewable fuels or blendstocks include bio-
butanol, biogas, cellulosic diesel, cellulosic gasoline, biofuel from
algae, jatropha, or palm, imported cellulosic ethanol, other biomass-
to-liquids (BTL), and other alcohols or ethers. We intend to revisit
these assumptions for the final rule and invite comment on whether
these renewable fuels or other potential fuels which have not been
included in our analyses should be included.
a. Cellulosic Biofuel
As defined in EISA, cellulosic biofuel means renewable fuel
produced from any cellulose, hemicellulose, or lignin that is derived
from renewable biomass and that has lifecycle greenhouse gas emissions,
as determined by the Administrator, that are at least 60% less than the
baseline lifecycle greenhouse gas emissions.
When many people think of cellulosic biofuel, they immediately
think of cellulosic ethanol. However, cellulosic biofuel could be
comprised of other alcohols, synthetic gasoline, synthetic diesel fuel,
and synthetic jet fuel, propane, and biogas. Whether cellulosic biofuel
is ethanol will depend on a number of factors, including production
costs, the form of tax subsidies, credit programs, and issues
associated with blending the biofuel into the fuel pool. It will also
depend on the relative demand for gasoline and diesel fuel. For
instance, European refineries are undersupplying the European market
with diesel fuel and oversupplying it with gasoline, and based on the
recent high diesel fuel price margins over gasoline, it seems that the
U.S. is falling in line with Europe. Therefore, if the U.S. trend is
toward being relatively oversupplied with gasoline, there could be a
price advantage towards producing renewable fuels that displace diesel
fuel rather than a gasoline fuel replacement like ethanol.
Current efforts in converting cellulosic feedstocks into fuels
focus on biochemical and thermochemical conversion processes.
Biochemical processes use live bacteria or isolated enzymes, or acids,
to break cellulose down into fermentable sugars. The advantage of using
live bacteria or enzymes is that simple carbon steel could be used
which helps to control the capital costs. However, bacteria and enzymes
that break down cellulose are generally specific to certain types of
cellulose, thus, the cellulosic biofuel facility may have difficulty
processing different types of feedstocks.\48\ If live bacteria are
used, the bacteria could be susceptible to contamination that could
force a plant shutdown. An example of a company using enzymes to
process cellulose into ethanol is Iogen, which has a demonstration
plant in Canada.
---------------------------------------------------------------------------
\48\ This is currently an area of intense research.
---------------------------------------------------------------------------
On the other hand, biochemical processes which rely on strong acids
will likely be less susceptible to contamination issues, and could more
easily process mixed feedstocks. Thus, strong acid biochemical
cellulosic ethanol plants could process MSW or a variety of feedstocks
which may be available in areas where no single feedstock dominates.
The strong acids, however, would likely require more expensive
metallurgy. A company which is planning to use strong acids to
hydrolyze the cellulose is Blue Fire Ethanol. Blue Fire is planning on
building a MSW plant in Southern California. Once cellulose is reduced
to simple sugars, either strong acid or enzymatic cellulosic ethanol
plants operate in a manner similar to a corn ethanol plant. This
consists of fermenting sugars into ethanol and then separating the
ethanol from the water that facilitated the fermentation step.
The thermochemical conversion process is very different from the
biochemical process right from the beginning. For the thermochemical
process, feedstocks are partially burned with oxygen at a very high
temperature and converted into a synthesis gas comprised of carbon
monoxide and hydrogen. The principal advantage of the thermochemical
process is that virtually any hydrocarbon material could be processed
as feedstock, as they would all be converted to the synthesis gas, even
if they produce different relative concentrations of carbon monoxide
and hydrogen. The synthesis gas is typically converted to ethanol or
diesel by one of several different processes.
Examples of companies currently pursuing the thermochemical route
to selectively produce ethanol include Range Ethanol and Coskata. Range
Ethanol is using a specially formulated catalyst that will primarily
produce ethanol, but it will produce other higher molecular weight
alcohols as well which would be recycled and mostly converted to
ethanol. Coskata, which is being supported by General Motors, is
planning on using bacteria to convert the synthesis gas to ethanol.
Another thermochemical plant could employ a very similar
gasification reactor, but instead of producing ethanol from syngas, a
Fischer Tropsch (F-T) reactor would be used to produce a primarily
diesel product, i.e., cellulosic diesel. The F-T reactor would use a
specially designed iron or cobalt catalyst to convert the syngas to
straight chain hydrocarbon compounds of varying lengths and molecular
weights. The heavier of these hydrocarbon compounds are then
hydrocracked to produce a very high percentage of valuable diesel fuel
and naphtha (gasoline type compounds). The F-T diesel fuel produced
from the F-T process is very high in quality due to its high cetane and
essentially zero sulfur level. While the naphtha produced from the F-T
process also contains essentially zero sulfur, it is very low in octane
and thus is a poor gasoline blendstock (although it could still be
desirable as a gasoline blendstock because of all the high octane
ethanol being blended into gasoline). Cellulosic naphtha is also
valuable as a cracking feedstock for producing various petrochemical
compounds. Since the F-T diesel is of better quality than the naphtha,
the heavier hydrocarbon compounds are selectively hydrocracked to
produce more diesel over naphtha.
No commercial cellulosic diesel plants currently exist in the U.S.,
nor elsewhere in the world. Currently, there is a cellulosic diesel
pilot plant operated by Choren in Germany and a commercial sized plant
in the planning stages by Choren also in Germany. Choren is planning to
employ woody materials and agricultural residue as feedstocks. Choren
specially developed a three-stage gasification process for dealing with
the complexities of
[[Page 24980]]
biomass and has partnered with Shell which has commercialized a F-T
reaction process. The Choren commercial cellulosic diesel plant in
Germany is expected to begin operating in 2010. Although coal-to-
liquids (CTL) plants rely on coal as their feedstock, they are very
similar to cellulosic diesel plants in design and help to demonstrate
the feasibility of the cellulosic diesel process. There are CTL pilot
plants which are operating today, as well as a number of commercial CTL
plants operating today or in the planning stages. Some of these plants
have experimented with or are being planned for co-feeding biomass
along with the coal. A current list of proposed cellulosic diesel and
CTL plants is provided in Chapter 1 of the DRIA.
In terms of production costs, at least for the current state of
technology, neither the biochemical nor thermochemical platforms
(comparing enzymatic biochemical processing to ethanol and
thermochemical processing to cellulosic diesel) appear to have clear
advantages in capital costs or operating costs.\49\ Other processing
techniques, for example, the syngas-to-ethanol process used by Coskata,
claim to be capable of producing at even lower production costs, but
without any commercial facilities operating today, it is hard to
predict how these other processing techniques differ from our estimates
of what the production costs for cellulosic biofuel facilities will be
in the future and which technology pathways will be most economic. As
such, both enzymatic biochemical and thermochemical technologies could
be key processing pathways for the production of cellulosic biofuel.
---------------------------------------------------------------------------
\49\ Wright, M. and Brown, R, ``Comparative Economics of
Biorefineries Based on the Biochemical and Thermochemical
Platforms,'' Biofuels, Bioprod. Bioref. 1:49-56, 2007.
---------------------------------------------------------------------------
The economic competitiveness of cellulosic biofuels will also
depend on the extent of financial support from the government. Under
the Farm Bill of 2008, both cellulosic ethanol and cellulosic diesel
receive the same tax subsidies ($1.01 per gallon each). The tax
subsidy, however, gives ethanol producers a considerable advantage over
those producing cellulosic diesel due to the feedstock quantity needed
per gallon produced (i.e., typically the higher the energy content of
the product, the more feedstock that is required). On an energy basis,
cellulosic ethanol would receive approximately $13/mmBtu while
cellulosic diesel would receive approximately $8/mmBtu. In a similar
manner, if we were to finalize an approach to the Equivalence Values
for generating RINs in which volume rather than energy content is the
basis, there would be an advantage for the production of cellulosic
ethanol over cellulosic diesel.
One large advantage that cellulosic diesel has over ethanol is the
ability for the fuel to be blended easily into the current distribution
infrastructure at sizeable volumes. There are currently factors tending
to limit the amount of ethanol that can be blended into the fuel pool
(see Section V.D. for more discussion). Thus, the production of
cellulosic diesel instead of cellulosic ethanol could help increase
consumption of renewable fuels.
Thus, there is uncertainty as to which mix of cellulosic biofuels
will be produced to fulfill the 16 Bgal mandate by 2022. The latest
release of AEO 2009, for example, estimates a mixture of cellulosic
diesel and ethanol produced for cellulosic biofuel. For assessing the
impacts of the RFS2 standards, we made the simplifying assumption that
cellulosic biofuel would only consist of ethanol, though market
realities may also result in cellulosic diesel and other products. We
are requesting comment on the types of cellulosic biofuel that should
be accounted for in our analyses and whether certain fuels are more
likely to come to fruition than others.
Cellulosic biofuel could also be produced internationally. One
example of internationally produced cellulosic biofuel is ethanol
produced from bagasse or straw from sugarcane processing in Brazil.
Currently, Brazil burns bagasse to produce steam and generate
bioelectricity. However, improving efficiencies over the coming decade
may allow an increasing portion of bagasse to be allocated to other
uses, including cellulosic biofuel, as the demand for bagasse for steam
and bioelectricity could remain relatively constant.
One recent study assessed the biomass feedstock potential for
selected countries outside the United States and projected supply
available for export or for biofuel production.50 51 For the
study's baseline projection in 2017, it was estimated that
approximately 21 billion ethanol-equivalent gallons could be produced
from cellulosic feedstocks at $36/dry tonne or less. The majority
(~80%) projected is from bagasse, with the rest from forest products.
Brazil was projected to have the most potential for cellulosic
feedstock production from both bagasse and forest products. Other
countries include India, China, and those belonging to the Caribbean
Basin Initiative (CBI), though much smaller feedstock supplies are
projected as compared to Brazil. Although international production of
cellulosic biofuel is possible, it is uncertain whether this supply
would be available primarily to the U.S. or whether other nations would
consume the fuel domestically. Therefore, for our analyses we have
chosen to assume that all the cellulosic biofuel used to comply with
RFS2 would be produced domestically.
---------------------------------------------------------------------------
\50\ Countries evaluated include Argentina, Brazil, Canada,
China, Colombia, India, Mexico, and CBI.
\51\ Kline, K. et al., ``Biofuel Feedstock Assessment for
Selected Countries,'' Oak Ridge National Laboratory, February 2008.
---------------------------------------------------------------------------
b. Biomass-Based Diesel
Biomass-based diesel as defined in EISA means renewable fuel that
is biodiesel as defined in section 312(f) of the Energy Policy Act of
1992 with lifecycle greenhouse gas emissions, as determined by the
Administrator, that are at least 50% less than the baseline lifecycle
greenhouse gas emissions. Biomass-based diesel can include fatty acid
methyl ester (FAME) biodiesel, renewable diesel (RD) that has not been
co-processed with a petroleum feedstock, as well as cellulosic diesel.
Although cellulosic diesel produced through the Fischer-Tropsch (F-T)
process could potentially contribute to the biomass-based diesel
category, we have assumed for our analyses that the fuel and its
corresponding feedstocks (cellulosic biomass) are already accounted for
in the cellulosic biofuel category discussed previously in Section
V.A.2.a.
FAME and RD processes can make acceptable quality fuel from
vegetable oils, fats, and greases, and thus will generally compete for
the same feedstock pool. For our analyses, we have assumed that the
volume contribution from FAME biodiesel and RD will be a function of
the available feedstock types. In our analysis we assumed that virgin
plant oils would be preferentially processed by biodiesel plants, while
the majority of fats and greases would be routed to RD
production.52 53 This is because the RD process involves
hydrotreating (or thermal depolymerization), which is more severe and
uses multiple chemical mechanisms to reform the fat molecules into
diesel range material. The FAME
[[Page 24981]]
process, by contrast, relies on more specific chemical mechanisms and
requires pre-treatment if the feedstocks contain more than trace
amounts of free fatty acids or other contaminates which are typical of
recycled fats and greases. In terms of volume availability of
feedstocks, supplies of fats and greases are more limited than virgin
vegetable oils. As a result, our control case assumes the majority of
biomass-based diesel volume is met using biodiesel facilities
processing vegetable oils, with RD making up a smaller portion and
using solely fats and greases.
---------------------------------------------------------------------------
\52\ Recent changes to federal tax subsidies and market shifts
may warrant changes to this assumption. We will reevaluate the
relative production volumes of biodiesel and renewable diesel for
the FRM.
\53\ This analysis was conducted prior to the completion of our
lifecycle analysis discussed in Section VI, and assumes the fuels
will meet the required GHG threshold.
---------------------------------------------------------------------------
The RD production volume must be further classified as co-processed
or non-co-processed, depending on whether the renewable material was
mixed with petroleum during the hydrotreating operations (more details
on this definition are in Section III.B.1). EISA specifically forbids
co-processed RD from being counted as biomass-based diesel, but it can
still count toward the total advanced biofuel requirement. What
fraction of RD will ultimately be co-processed is uncertain at this
time, since little or no commercial production of RD is currently
underway, and little public information is available about the
comparative economics and feasibility of the two methods. We assumed in
our control case that half the material will be non-co-processed and
thus qualify as biomass-based diesel. We invite comment on whether RD
production will favor co-processing or non-co-processing with a
petroleum feedstock in the future.
Perhaps the feedstock with the greatest potential for providing
large volumes of oil for the production of biomass-based diesel is
microalgae. Algae grown on land in photo-bioreactors or in open ponds
could potentially yield 15 to 50 times more oil per acre than
traditional oil crops such as soy, rapeseed, or oil palm. Additionally
it can be cultivated on marginal land with low nutrient inputs, and
thus does not suffer from the sheer resource constraints that make
other biofuel feedstocks problematic at large scale. However, several
technical hurdles do still exist. Specifically, more efficient
harvesting, dewatering and lipid extraction methods are needed to lower
costs to a level competitive with other biodiesel feedstocks (20-30% of
current costs). Until these hurdles are overcome, it is unlikely that
algae-based biodiesel can be commercially competitive with other
biodiesel fuels. Thus, for our control case we have chosen not to
include oil from algae as a feedstock. Although the majority of algae
to biofuel companies are focusing on producing algae oil for
traditional biodiesel production, several companies are alternatively
using algae for producing ethanol or crude oil for gasoline or diesel
which could also help contribute to the advanced biofuel mandate.\54\
For more detail on algae as a feedstock refer to Section 1.1 of the
DRIA.
---------------------------------------------------------------------------
\54\ Algenol and Sapphire Energy, see http://www.algenolbiofuels.com/ and http://www.sapphireenergy.com/.
---------------------------------------------------------------------------
Jatropha curcas, a shrub native to Central America, is yet another
possible biofuel feedstock. The perennial yields oil-rich seeds yearly,
with oil yields per acre up to 4 times that of soy and twice that of
rapeseed under optimal conditions. It can grow on low-nutrient lands,
and is tolerant of drought. However, jatropha yields under these
marginal conditions are hard to predict because of insufficient
commercial experience; it is possible that jatropha will have low
yields in the sub-optimal conditions where its cultivation would be
most advantageous. Furthermore, jatropha seed harvesting is very labor
intensive, and little is known about the crop's sustainability impacts,
its long-term yield, or the feasibility of cultivation as a
monoculture. It is unlikely that jatropha can be cultivated in the
United States economically or sustainably, and the possibility of
importing jatropha oil or biodiesel from producing countries is very
uncertain because overseas cultivation efforts are still underdeveloped
and initial volumes will likely be used domestically. As a result, we
have not projected the use of jatropha as a feedstock under our control
case. For more detail on the potential use of jatropha refer to Section
1.1 of the DRIA.
c. Other Advanced Biofuel
As defined in EISA, advanced biofuel means renewable fuel, other
than ethanol derived from corn starch, that has lifecycle greenhouse
gas emissions, as determined by the Administrator, that are at least
50% less than baseline lifecycle greenhouse gas emissions. As described
more fully in Section VI.D, we are proposing that the GHG threshold for
advanced biofuels be adjusted to 44% or potentially as low as 40%
depending on the results from the analyses that will be conducted for
the final rule. As defined in EISA, advanced biofuel includes the
cellulosic biofuel, biomass-based diesel, and co-processed renewable
diesel categories that were mentioned in Sections V.A.2.a and V.A.2.b
above. However, EISA requires greater volumes of advanced biofuel than
just the volumes required of these fuels; see Table V.A.2-1. It is
entirely possible that greater volumes of cellulosic biofuel, biomass-
based diesel, and co-processed renewable diesel than required by EISA
could be produced in the future. Our control case, however, does not
assume that cellulosic biofuel and biomass-based diesel volumes will
exceed those required under EISA.\55\ As a result, to meet the total
advanced biofuel volume required under EISA, advanced biofuel types are
needed other than cellulosic biofuel, biomass-based diesel, and co-
processed renewable diesel through 2022.
---------------------------------------------------------------------------
\55\ While cellulosic biofuel will not be limited by feedstock
availability, it likely will be limited by the very aggressive ramp
up in production volume for an industry which is still being
demonstrated on the pilot scale and therefore is not yet
commercially viable. On the other hand, biomass-based diesel derived
from agricultural oils and animal fats are faced with relatively
high feedstock costs which limit feedstock supply.
---------------------------------------------------------------------------
We have assumed for our control case that the most likely source of
advanced fuel other than cellulosic biofuel, biomass-based diesel, and
co-processed renewable diesel would be from imported sugarcane
ethanol.\56\ Our assessment of international fuel ethanol production
and demand indicate that anywhere from 3.8-4.2 Bgal of sugarcane
ethanol from Brazil could be available for export by 2020/2022. If this
volume were to be made available to the U.S., then there would be
sufficient volume to meet the advanced biofuel standard. To calculate
the amount of imported ethanol needed to meet the EISA standards, we
took the difference between the total advanced biofuel category and
cellulosic biofuel, biomass-based diesel, and co-processed renewable
diesel categories. The amount of imported ethanol required by 2022 is
approximately 3.2 Bgal. We solicit comment on our estimate of 3.2 Bgal
and whether or not it is reasonable to assume that Brazil (or any other
country) could satisfy this demand.
---------------------------------------------------------------------------
\56\ This analysis was conducted prior to the completion of our
lifecycle analysis discussed in Section VI, and assumes the fuel
will meet the required GHG threshold.
---------------------------------------------------------------------------
Recent news indicates that there are also plans for sugarcane
ethanol to be produced in the U.S in places where the sugar subsidy
does not apply. For instance, sugarcane has been grown in California's
Imperial Valley specifically for the purpose of making ethanol and
using the cane's biomass to generate electricity to power the ethanol
distillery as well as export excess electricity to the electric
grid.\57\ There are at least two projects being developed at this time
that could result in several
[[Page 24982]]
hundred million gallons of ethanol produced. The sugarcane is being
grown on marginal and existing cropland that is unsuitable for food
crops and will replace forage crops like alfalfa, Bermuda grass, Klein
grass, etc. Harvesting is expected to be fully mechanized. Thus, there
is potential for these projects and perhaps others to help contribute
to the EISA biofuels mandate. This could lower the volume needed to be
imported from Brazil.
---------------------------------------------------------------------------
\57\ Personal communication with Nathalie Hoffman, Managing
Member of California Renewable Energies, LLC, August 27, 2008.
---------------------------------------------------------------------------
Butanol is another potential motor vehicle fuel which could be
produced from biomass and used in lieu of ethanol to comply with the
RFS2 standard. Production of butanol is being pursued by a number of
companies including a partnership between BP and Dupont. Other
companies which have expressed the intent to produce biobutanol are
Baer Biofuels and Gevo. The near term technology being pursued for
producing butanol involves fermentation of starch compounds, although
it can also be produced from cellulose. Butanol has several inherent
advantages compared to ethanol. First, it has higher energy density
than ethanol which would improve fuel economy (mpg). Second, butanol is
much less water soluble which may allow the butanol to be blended in at
the refinery and the resulting butanol-gasoline blend then more easily
shipped through pipelines. This would reduce distribution costs
associated with ethanol's need to be shipped separately from its
gasoline blendstock and also save on the blending costs incurred at the
terminal. Third, butanol can be blended in higher concentrations than
10% which would likely allow butanol to be blended with gasoline at
high enough concentrations to avoid the need for most or all of high
concentration ethanol-gasoline blends, such as E85, that require the
use of fuel flexible vehicles. For example, because of butanol's lower
oxygen content, it can be blended at 16% (by volume) to match the
oxygen concentration of ethanol blended at 10% (by volume).\58\ Because
of butanol's higher energy density, when blending butanol at 16% by
volume, it is the renewable fuels equivalent to blending ethanol at
about 20 percent. Thus, butanol would enable achieving most of the RFS2
standard by blending a lower concentration of renewable fuel than
having to resort to a sizable volume of E85 as in the case of ethanol.
As pointed out in Section V.D., the need to blend ethanol as E85
provides some difficult challenges. The use of butanol may be one means
of avoiding these blending difficulties.
---------------------------------------------------------------------------
\58\ To obtain EPA approval for butanol blends as high as 16% by
volume would require that the butanol be blended with an approved
corrosion inhibitor.
---------------------------------------------------------------------------
At the same time, butanol has a couple of less desirable aspects
relative to ethanol. First, butanol is lower in octane compared to
ethanol--ethanol has a very high blending octane of around 115, while
butanol's octane ranges from 87 octane numbers for normal butanol and
94 octane numbers for isobutanol. Potential butanol producers are
likely to pursue producing isobutanol over normal butanol because of
isobutanol's higher octane content. Higher octane is a valuable
attribute of any gasoline blendstock because it helps to reduce
refining costs. A second negative property of butanol is that it has a
much higher viscosity compared to either gasoline or ethanol. High
viscosity makes a fuel harder to pump, and more difficult to atomize in
the combustion chamber in an internal combustion engine. The third
downside to butanol is that it is more expensive to produce than
ethanol, although the higher production cost is partially offset by its
higher energy density.
Another potential source of renewable transportation fuel is
biomethane refined from biogas. Biogas is a term meaning a combustible
mixture of methane and other light gases derived from biogenic sources.
It can be combusted directly in some applications, but for use in
highway vehicles it is typically purified to closely resemble fossil
natural gas for which the vehicles are typically designed. The
definition of biogas as given in EISA is sufficiently broad to cover
combustible gases produced by biological decomposition of organic
matter, as in a landfill or wastewater treatment facility, as well as
those produced via thermochemical decomposition of biomass.
Currently, the largest source of biogas is landfill gas collection,
where the majority of fuel is combusted to generate electricity, with a
small portion being upgraded to methane suitable for use in heavy duty
vehicle fleets. Current literature suggests approximately 16 billion
gasoline gallons equivalent of biogas (referring to energy content)
could potentially be produced in the long term, with about two thirds
coming from biomass gasification and about one third coming from waste
streams such as landfills and human and animal sewage
digestion.59 60
---------------------------------------------------------------------------
\59\ National Renewable Energy Laboratory estimate based on
biomass portion available at $45-$55/dry ton. Using POLYSYS Policy
Analysis System, Agricultural Policy Analysis Center, University of
Tennessee. http://www.agpolicy.org/polysys.html. Accessed May 2008.
\60\ Milbrandt, A., ``Geographic Perspective on the Current
Biomass Resource Availability in the United States.'' 70 pp., NREL
Report No. TP-560-39181, 2005.
---------------------------------------------------------------------------
Because the majority of the biogas volume estimates assume biomass
as a feedstock, we have chosen not to include this fuel in our analyses
since we are projecting most available biomass will be used for
cellulosic liquid biofuel production in the long term. The remaining
biogas potentially available from waste-related sources would come from
a large number of small streams requiring purification and connection
to storage and/or distribution facilities, which would involve
significant economic hurdles. An additional and important source of
uncertainty is whether there would be a sufficient number of vehicles
configured to consume these volumes of biogas. Thus, we expect future
biogas fuel streams to continue to find non-transportation uses such as
electrical power generation or facility heating.
d. Other Renewable Fuel
The remaining portion of total renewable fuel not met with advanced
biofuel is assumed to come from corn-based ethanol. EISA effectively
sets a limit for participation in the RFS program of 15 Bgal of corn
ethanol by 2022. It should be noted, however, that there is no specific
``corn-ethanol'' mandated volume, and that any advanced biofuel
produced above and beyond what is required for the advanced biofuel
requirements could reduce the amount of corn ethanol needed to meet the
total renewable fuel standard. This occurs in our projections during
the earlier years (2009-2014) in which we project that some fuels could
compete favorably with corn ethanol (e.g. biodiesel and imported
ethanol). Beginning around 2015, fuels qualifying as advanced biofuels
likely will be devoted to meeting the increasingly stringent volume
mandates for advanced biofuel. It is also worth noting that more than
15 Bgal of corn ethanol could be produced and RINs generated for that
volume under our proposed RFS2 regulations. However, obligated parties
would not be required to purchase more than 15 Bgal worth of corn
ethanol RINs.
We are assuming for our analysis that sufficient corn ethanol will
be produced to meet the 15 Bgal limit. However, this assumes that in
the future corn ethanol production is not limited due to environmental
constraints, such as water quantity issues (see Section 6.10 of the
DRIA). This also assumes that in
[[Page 24983]]
the future either corn ethanol plants are constructed or modified to
meet the 20% GHG threshold, or that sufficient corn ethanol production
exists that is grandfathered and not required to meet the 20%
threshold. Our current projection is that up to 15 Bgal could be
grandfathered, but actual volumes will be determined at the time of
facility registration. Refer to Section 1.5.1.4 of the DRIA for more
information. Since our current lifecycle analysis estimates that much
of the current corn ethanol would not meet the 20% GHG reduction
threshold required of non-grandfathered facilities without facility
upgrades, then if actual grandfathered corn volumes are less than 15
Bgal it may be necessary to meet the volume mandate with other
renewable fuels or through the use of advanced technologies that could
improve the corn ethanol lifecycle GHG estimates.
B. Renewable Fuel Production
1. Corn/Starch Ethanol
The majority of domestic biofuel production currently comes from
plants processing corn and other similarly-processed grains in the
Midwest. However, there are a handful of plants located outside the
Corn Belt and a few plants processing simple sugars from food or
beverage waste. In this section, we will summarize the present state of
the corn/starch ethanol industry and discuss how we expect things to
change in the future under the proposed RFS2 program.
a. Historic/Current Production
The United States is currently the largest ethanol producer in the
world. In 2008, the U.S. produced almost nine billion gallons of fuel
ethanol for domestic consumption, the majority of which came from
locally-grown corn.\61\ Although the U.S. ethanol industry has been in
existence since the 1970s, it has rapidly expanded over the past few
years due to the phase-out of methyl tertiary butyl ether (MTBE),\62\
elevated crude oil prices, state mandates and tax incentives, the
introduction of the Federal Volume Ethanol Excise Tax Credit
(VEETC),\63\ and the implementation of the existing RFS1 program.\64\
As shown in Figure V.B.1-1, U.S. ethanol production has grown
exponentially over the past decade.
---------------------------------------------------------------------------
\61\ Based on total transportation ethanol reported in EIA's
March 2009 Monthly Energy Review (Table 10.2) less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
\62\ For more information on how the phase-out of MTBE helped
spur ethanol production/consumption, refer to Section V.D.1.
\63\ On October 22, 2004, President Bush signed into law H.R.
4520, the American Jobs Creation Act of 2004 (JOBS Bill), which
created the Volumetric Ethanol Excise Tax Credit (VEETC). The $0.51/
gal VEETC for ethanol blender replaced the former fuel excise tax
exemption, blender's credit, and pure ethanol fuel credit. However,
the recently-enacted 2008 Farm Bill modifies the alcohol credit so
that corn ethanol gets a reduced credit of $0.45/gal and cellulosic
biofuel a credit of $1.01/gal effective January 1, 2009.
\64\ On May 1, 2007, EPA published a final rule (72 FR 23900)
implementing the Renewable Fuel Standard (RFS) required by EPAct.
The RFS requires that 4.0 billion gallons of renewable fuel be
blended into gasoline/diesel by 2006, growing to 7.5 billion gallons
by 2012.
\65\ Based on total transportation ethanol reported in EIA's
March 2009 Monthly Energy Review (Table 10.2) less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
[GRAPHIC] [TIFF OMITTED] TP26MY09.004
[[Page 24984]]
As of April 1, 2009, there were 169 corn/starch ethanol plants
operating in the U.S. with a combined estimated production capacity of
10.5 billion gallons per year.\66\ This does not include a number of
ethanol plants that are currently idled.\67\ The majority of today's
ethanol (over 91% by volume) is produced exclusively from corn. Another
8% comes from a blend of corn and/or similarly processed grains (milo,
wheat, or barley) and less than half a percent is produced from cheese
whey, waste beverages, and sugars/starches combined. A summary of U.S.
ethanol production by feedstock is presented in Table V.B.1-1.
---------------------------------------------------------------------------
\66\ Our April 2009 corn/starch ethanol industry
characterization was based on a variety of sources including:
Renewable Fuels Association (RFA) Ethanol Biorefinery Locations
(updated March 31, 2009); Ethanol Producer Magazine (EPM) Producing
plant list (last modified on April 7, 2009), and ethanol producer
Web sites. The baseline does not include ethanol plants whose
primary business is industrial or food-grade ethanol production nor
does it include plants that might be located in the Virgin Islands
or U.S. territories. Where applicable, current/historic production
levels have been used in lieu of nameplate capacities to estimate
production capacity. The April 2009 information presented in this
section reflects our most recent knowledge of the corn/starch
ethanol industry. However, for various NPRM impact analyses, an
earlier May 2008 industry assessment was used. For more on this
assessment, refer to Section 1.5.1.5 of the DRIA.
\67\ In addition to idled plants, the assessment does not
include idled production capacity at facilities that are currently
operating at 50% or less than their nameplate capacity.
Table V.B.1-1--Current Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
Capacity Percent of Number of Percent of
Plant feedstock (Primary listed first) MGY capacity plants plants
----------------------------------------------------------------------------------------------------------------
Corn \a\.................................................... 9,605 91.2 144 85.2
Corn, Milo \b\.............................................. 717 6.8 14 8.3
Corn, Wheat................................................. 130 1.2 1 0.6
Milo........................................................ 3 0.0 1 0.6
Wheat, Milo................................................. 50 0.5 1 0.6
Cheese Whey................................................. 5 0.0 1 0.6
Waste Beverages \c\......................................... 19 0.2 5 3.0
Waste Sugars & Starches \d\................................. 7 0.1 2 1.2
---------------------------------------------------
Total................................................... 10,535 100 169 100
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, two facilities also operating pilot-level cellulosic ethanol
plants at these locations, and four facilities planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.
As shown in Table V.B.1-1, of the 169 operating plants, 161 process
corn and/or other similarly processed grains. Of these facilities, 150
utilize dry-milling technologies and the remaining 11 plants rely on
wet-milling processes. Dry mill ethanol plants grind the entire kernel
and generally produce only one primary co-product: Distillers grains
with solubles (DGS). The co-product is sold wet (WDGS) or dried (DDGS)
to the agricultural market as animal feed. However, there are a growing
number of dry mill ethanol plants pursuing front-end fractionation or
back-end extraction to produce fuel-grade corn oil for the biodiesel
industry. There are also additional plants pursuing cold starch
fermentation and other energy-saving processing technologies. For more
on the dry-milling and wet-milling processes as well as emerging
advanced technologies, refer to Section 1.4 of the DRIA.
In contrast to dry mill plants, wet mill facilities separate the
kernel prior to processing into its component parts (germ, fiber,
protein, and starch) and in turn produce other co-products (usually
gluten feed, gluten meal, and food-grade corn oil) in addition to DGS.
Wet mill plants are generally more costly to build but are larger in
size on average.\68\ As such, 11.5% of the current grain ethanol
production comes from the 11 previously-mentioned wet mill facilities.
The remaining eight plants which process cheese whey, waste beverages
or sugars/starches, operate differently than their grain-based
counterparts. These small production facilities do not require milling
and operate a simpler enzymatic fermentation process.
---------------------------------------------------------------------------
\68\ According to our April 2009 corn ethanol plant assessment,
the average wet mill plant capacity was 111 million gallons per
year--almost twice that of the average dry mill plant capacity (62
million gallons per year). For more on average plant sizes, refer to
Section 1.5.1.1 of the DRIA.
---------------------------------------------------------------------------
Ethanol production is a relatively resource-intensive process that
requires the use of water, electricity, and steam.\69\ Steam needed to
heat the process is generally produced on-site or by other dedicated
boilers.\70\ The ethanol industry relies primarily on natural gas. Of
today's 169 ethanol production facilities, 142 burn natural gas \71\
(exclusively), three burn a combination of natural gas and biomass, one
recently started burning a combination of natural gas, landfill biogas
and wood, and two burn a combination of natural gas and syrup from the
process. In addition, 20 plants burn coal as their primary fuel and one
burns a combination of coal and biomass. Our research suggests that 25
plants currently utilize cogeneration or combined heat and power (CHP)
technology, although others may exist. CHP is a mechanism for improving
overall plant efficiency. Whether owned by the ethanol facility, their
local utility, or a third party, CHP facilities produce their own
electricity and use the waste heat from power production for process
steam, reducing the energy intensity of ethanol production.\72\ A
summary of the energy sources and CHP technology utilized by today's
ethanol plants is found in Table V.B.1-2.
---------------------------------------------------------------------------
\69\ For more information on plant energy requirements, refer to
Section 1.5.1.3 of the DRIA.
\70\ We are also aware of a couple plants that pull steam
directly from a nearby utility.
\71\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
\72\ For more on CHP technology, refer to Section 1.4.1.3 of the
DRIA.
[[Page 24985]]
Table V.B.1-2--Current Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
Capacity Percent of Number of Percent of
Plant energy source (primary listed first) MGY capacity plants plants CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\....................................... 1,868 17.7 20 11.8 9
Coal, Biomass.................................. 50 0.5 1 0.6 0
Natural Gas \b\................................ 8,294 78.7 142 84.0 15
Natural Gas, Biomass \c\....................... 113 1.1 3 1.8 1
Natural Gas, Landfill Biogas, Wood............. 110 1.0 1 0.6 0
Natural Gas, Syrup............................. 101 1.0 2 1.2 0
----------------------------------------------------------------
Total...................................... 10,535 100.0 169 100.0 25
----------------------------------------------------------------------------------------------------------------
\a\ Includes four plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition
to coal and one facility that intends to transition to biomas in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
biogas, and two facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.
Since the majority of ethanol is made from corn, it is no surprise
that most of the plants are located in the Midwest near the Corn Belt.
Of today's 169 ethanol production facilities, 151 are located in the 15
states comprising PADD 2. For a map of the Petroleum Administration for
Defense Districts or PADDs, refer to Figure V.B.1-2.
[GRAPHIC] [TIFF OMITTED] TP26MY09.005
As a region, PADD 2 accounts for 94% (or almost 10 billion gallons)
of today's estimated ethanol production capacity, as shown in Table
V.B.1-3. For more information on today's ethanol plants and a detailed
map of their locations, refer to Section 1.5 of the DRIA.
Table V.B.1-3--Current Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
Capacity Percent of Number of Percent of
PADD MGY capacity plants plants
----------------------------------------------------------------------------------------------------------------
PADD 1...................................................... 150 1.4 3 1.8
PADD 2...................................................... 9,900 94.0 151 89.3
PADD 3...................................................... 194 1.8 3 1.8
PADD 4...................................................... 160 1.5 7 4.1
PADD 5...................................................... 131 1.2 5 3.0
---------------------------------------------------
Total................................................... 10,535 100.0 169 100.0
----------------------------------------------------------------------------------------------------------------
The U.S. ethanol industry is currently comprised of a mixture of
company-owned plants and locally-owned farmer cooperatives (co-ops).
The majority of today's ethanol production facilities are company-
owned, and on average these plants are larger in size than farmer-owned
co-ops. Accordingly, company-owned plants account for more than 79% of
today's ethanol production capacity.\73\ Furthermore, 30% of the total
domestic product comes from 38 plants owned by just three different
companies--POET Biorefining, Archer Daniels Midland (ADM), and Valero
Renewables.\74\
---------------------------------------------------------------------------
\73\ Farmer-owned plant status derived from Renewable Fuels
Association (RFA), Ethanol Biorefinery Locations (updated March 31,
2009). For more on average plant sizes, refer to Section 1.5.1 of
the DRIA.
\74\ Valero recently entered into the renewable fuels business
by acquiring five idled corn ethanol plants and one construction
site formerly owned by VeraSun Energy Corporation. Valero has since
purchased two more idled VeraSun plants, but they have not been
brought back online yet.
---------------------------------------------------------------------------
[[Page 24986]]
b. Forecasted Production Under RFS2
As highlighted above, 10.5 billion gallons of corn/starch ethanol
plant capacity was online as of April 1, 2009. So even if no additional
capacity was added, U.S. ethanol production would grow from 2008 to
2009, provided facilities continue to operate at or above today's
production levels. And despite today's temporary unfavorable market
conditions (i.e., low ethanol market values), we expect the ethanol
industry will continue to expand in the future under RFS2. Although
there is not a set corn ethanol standard, EISA allows for 15 billion
gallons of the 36-billion gallon renewable fuel standard to be met by
conventional biofuels. And we expect that corn and other sugar or
starch-based ethanol will fulfill this requirement. Furthermore, we
project that all new corn/starch ethanol plant capacity brought online
under RFS2 would either meet the conventional biofuel GHG threshold
requirement \75\ or meet the grandfathering requirement (for more
information, refer to Section 1.5.1.4 of the DRIA).
---------------------------------------------------------------------------
\75\ The lifecycle assessment values which assume a 2% discount
rate over a 100-year timeframe.
---------------------------------------------------------------------------
In addition to the 169 corn/starch ethanol plants that are
currently online today, 36 plants are presently idled. Some of these
constructed facilities (namely smaller ethanol plants) have been idled
for quite some time, whereas other plants have just recently been put
into ``hot idle'' mode. A number of ethanol producers (e.g., VeraSun)
are idling operations, putting projects on hold, selling off plants,
and even filing for Chapter 11 bankruptcy. In addition, we are aware of
two facilities that are currently operating at 50% or less than their
nameplate capacity. As crude oil and gasoline prices rise again in the
future, corn ethanol production will become more viable again and we
expect that these plants will resume operations. At the time of our
April 2009 ethanol industry assessment, there were also 19 new ethanol
plants under construction in the U.S, and two plant expansion projects
underway. While many of these projects are also on hold due to the
current economic conditions, we expect these facilities will eventually
come online under the RFS2 program. A summary of the projected industry
growth is found in Table V.B.1-4.\76\
---------------------------------------------------------------------------
\76\ Idled plants and construction projects based on Renewable
Fuels Association (RFA) Ethanol Biorefinery Locations (updated March
31, 2009); Ethanol Producer Magazine (EPM) Not Producing and Under
Construction plant lists (last modified on April 7, 2009), ethanol
producer Web sites, and follow-up correspondence with ethanol
producers. It is worth noting that for our industry assessment,
``under construction'' implies that more than just a ground breaking
ceremony has taken place.
Table V.B.1-4--Potential Industry Expansion Under RFS2
----------------------------------------------------------------------------------------------------------------
Growth in ethanol production
-------------------------------------------------------------------------------
Plants New
currently Idled plants/ construction Expansion Total
online capacity \a\ projects projects
----------------------------------------------------------------------------------------------------------------
Plant Capacity (MGY)............ 10,535 2,471 1,955 80 15,042
Total No. of Plants............. 169 36 19 2 226
----------------------------------------------------------------------------------------------------------------
\a\ Includes the idled plant capacity of the two facilities that are currently operating at 50% or less than
nameplate capacity.
While theoretically it only takes 12 to 18 months to build an
ethanol plant,\77\ the rate at which new plant capacity comes online
will be dictated by market conditions, which will in part be influenced
by the RFS2 requirements. As mentioned above, today's proposed program
will create a growing demand for corn ethanol reaching 15 billion
gallons by 2015. However, it is possible that market conditions could
drive demand even higher. Whether the nation will overcomply with the
corn ethanol standard is uncertain and will be determined by feedstock
availability/pricing, crude oil pricing, and the relative ethanol/
gasoline price relationship. To measure the impacts of the proposed
RFS2 program, we assumed that corn ethanol production would not exceed
15 billion gallons. We also assumed that all growth would come from new
plants or plant expansion projects (in addition to idled plants being
brought back online).\78\ However, it is possible that some of the
growth could come from minor process improvements (e.g.,
debottlenecking) at existing facilities.
---------------------------------------------------------------------------
\77\ For more information on plant build rates, refer to Section
1.2.5 of the RIA.
\78\ For our NPRM impact analyses, we relied on an earlier May
2008 industry assessment. For more information, refer to Section
1.5.1.5 of the DRIA.
---------------------------------------------------------------------------
Once all the aforementioned projects are complete, we project that
there would be 226 corn/starch ethanol plants operating in the U.S.
with a combined production capacity of around 15 billion gallons per
year. Much like today's ethanol industry, the overwhelming majority of
new production capacity (93% by volume) is expected to come from corn-
fed plants. Another 7% is forecasted to come from plants processing a
blend of corn and other grains, and a very small increase is projected
to come from idled cheese whey and waste beverage plants coming back
online. A summary of the forecasted ethanol production by feedstock
under the RFS2 program is found in Table V.B.1-5.
Table V.B.1-5--Projected RFS2 Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
Additional production Total RFS2 estimate
---------------------------------------------------
Plant feedstock (primary listed first) Capacity Number of Capacity Number of
MGY plants MGY plants
----------------------------------------------------------------------------------------------------------------
Corn \a\.................................................... 4,197 49 13,802 193
Corn, Milo \b\.............................................. 185 3 902 17
Corn, Wheat................................................. 8 1 138 2
Corn, Wheat, Milo........................................... 110 2 110 2
Milo........................................................ 0 0 3 1
Wheat, Milo................................................. 0 0 50 1
[[Page 24987]]
Cheese Whey................................................. 3 1 8 2
Waste Beverages \c\......................................... 4 1 23 6
Waste Sugars & Starches \d\................................. 0 0 7 2
---------------------------------------------------
Total................................................... 4,507 57 15,042 226
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, another facility processing small amounts of whey, two
facilities also operating pilot-level cellulosic ethanol plants at these locations, and four facilities
planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.
Based on current industry plans, the majority of additional corn/
grain ethanol production capacity (almost 84% by volume) is predicted
to come from new or expanded plants burning natural gas.\79\
Additionally, we are forecasting one new plant and a reopening of
another plant relying on manure biogas. We are also predicting
expansions at three coal-fired ethanol plants.\80\ Of the 55 new
ethanol plants, our research indicates that five would utilize
cogeneration, bringing the total number of CHP facilities to 30. A
summary of the projected near-term ethanol plant energy sources is
found in Table V.B.1-6.
---------------------------------------------------------------------------
\79\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
\80\ Two of the three coal-fired plant expansions appear as new
plants in Table V.B.1-6. This is because two of the expansion
projects consist of adding dry milling plant capacity to an existing
wet mill plant. However, our interpretation is that these facilities
will rely on the same (potentially expanded) coal-fired boilers for
process steam. Since all the aforementioned coal-fired ethanol
production facilities appear to have commenced construction prior to
December 19, 2007, we project that the ethanol produced at these
facilities will be grandfathered under the proposed RFS2 rule. For
more on our grandfathered volume estimate, refer to Section 1.5.1.4
of the DRIA.
Table V.B.1-6--Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
Additional production Total RFS2 estimate
----------------------------------------------------------------
Plant energy source (primary listed first) Capacity Number of Capacity Number of
MGY plants MGY plants CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\....................................... 610 2 2,478 22 11
Coal, Biomass.................................. 0 0 50 1 0
Manure Biogas.................................. 134 2 134 2 0
Natural Gas \b\................................ 3,763 53 12,056 195 18
Natural Gas, Biomass \c\....................... 0 0 113 3 1
Natural Gas, Landfill Biogas, Wood............. 0 0 110 1 0
Natural Gas, Syrup............................. 0 0 101 2 0
----------------------------------------------------------------
Total...................................... 4,507 57 15,042 226 30
----------------------------------------------------------------------------------------------------------------
\a\ Includes six plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to
coal and one facility that intends to transition to biomass in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
biogas, and six facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.
The information in Table V.B.1.6 is based on short-term industry
production plans at the time of our April 1, 2009 plant assessment.
However, we are anticipating growth in advanced ethanol production
technologies under the proposed RFS2 program. We project that fuel
prices will drive a large number of corn ethanol plants to transition
from conventional boiler fuels to advanced biomass-based feedstocks. We
also believe that fossil fuel/electricity prices will drive a number of
ethanol producers to pursue CHP technology. For more on our projected
2022 utilization of these technologies under the RFS2 program, refer to
Section 1.5.1.3 of the DRIA.
Under the proposed RFS2 program, the majority of new ethanol
production is expected to originate from PADD 2, close to where most of
the corn is grown. However, there are a number of ``destination''
ethanol plants being built outside the Midwest in response to
production subsidies, E10/E85 retail pump incentives, and state
mandates. A summary of the forecasted ethanol production by PADD under
the RFS2 program can be found in Table V.B.1-7.
[[Page 24988]]
Table V.B.1-7--Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
Additional production Total RFS2 Estimate
---------------------------------------------------
PADD Capacity Number of Capacity Number of
MGY plants MGY plants
----------------------------------------------------------------------------------------------------------------
PADD 1...................................................... 178 3 328 6
PADD 2...................................................... 3,566 43 13,466 194
PADD 3...................................................... 350 4 544 7
PADD 4...................................................... 50 1 210 8
PADD 5...................................................... 363 6 494 11
---------------------------------------------------
Total................................................... 4,507 57 15,042 226
----------------------------------------------------------------------------------------------------------------
2. Cellulosic Biofuel
Ethanol currently dominates U.S. biofuel production, and more
specifically, ethanol produced from corn and other grains. However,
cellulosic feedstocks have the potential to greatly expand domestic
ethanol production, both volumetrically and geographically. It is also
possible to produce synthetic diesel fuel from cellulosic feedstocks
(also known as ``cellulosic diesel'') through a Fischer-Tropsch
gasification process or a thermal depolymerization process. We are also
aware of one company using live bacteria to break down biomass and
produce cellulosic diesel and other petroleum replacements. Before
wide-scale commercialization of cellulosic biofuel can occur in today's
marketplace, technical and logistical barriers must be overcome. In
addition to today's RFS2 program which sets aggressive goals for all
ethanol production, the Department of Energy (DOE) and other federal
and state agencies are helping to spur industry growth.
a. Current Production/Plans
The cellulosic biofuel industry is essentially in its infancy. With
the exception of a 20 million-gallon-per year cellulosic diesel plant
recently opened by Cello Energy in Bay Minette, AL, the majority of
facilities in operation today are small pilot- or demonstration-level
plants. Most of these facilities operate intermittently and produce
insignificant volumes of biofuel. Some researchers are focusing on
processing corn residues, e.g., corn stover, cobs, and/or fiber. Some
are focusing on other agricultural residues such as sugarcane bagasse,
rice and wheat straw. Others are looking at waste products such as
forestry residues, citrus residues, pulp or paper mill waste, municipal
solid waste (MSW), and construction and demolition (C&D) debris.
Dedicated energy crops including switchgrass and poplar trees are also
being investigated.
Based on an April 2009 assessment of information available on the
public domain, there are currently 25 pilot- and demonstration-level
(or smaller) cellulosic ethanol plants operating in the United States.
However, only 9 of these plants report measurable volumes of ethanol
production. In addition, we are aware of one pilot-level cellulosic
diesel plant in addition to the commercial-level Cello Energy
plant.\81\ A summary of these 11 facilities totaling just over 23
million gallons of annual production capacity is provided in Table
V.B.2-1. The date listed in the table indicates when the facility first
began operations. For more on the existing cellulosic ethanol and
diesel plants, refer to Sections 1.5.3.1 and 1.5.3.3 of the DRIA.
---------------------------------------------------------------------------
\81\ Our April 2009 cellulosic ethanol industry characterization
was based on researching DOE- and USDA-supported projects, plants
referenced in HART's Ethanol & Biodiesel News (through the April 14,
2009 issue), plants included on the Cellulosic Ethanol Site (http://www.thecesite.com/), and plants referenced on other biofuel industry
Web sites.
Table V.B.2-1--Existing Cellulosic Biofuel Plants
----------------------------------------------------------------------------------------------------------------
Prod Est.
Company or organization name Location Feedstocks cap Op. Conv. tech.
(MGY) date \a\
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
Abengoa Bioenergy Corporation York, NE................. Wheat straw, corn 0.02 Sep-07 Bio.
\b\. stover, energy
crops.
Bioengineering Resources, Inc. Fayetteville, AR......... MSW, wood waste, 0.04 1998 Therm.
(BRI). coal.
BPI & Universal Entech.......... Phoenix, AZ.............. Paper waste 0.01 2004 Bio.
(sorted MSW).
Gulf Coast Energy............... Livingston, AL........... Wood waste (sorted 0.20 Dec-08 Therm.
MSW).
Mascoma Corporation............. Rome, NY................. Wood chips........ 0.20 Feb-09 Bio.
POET Project Bell \b\........... Scotland, SD............. Corn cobs & fiber. 0.02 Jan-09 Bio.
Verenium........................ Jennings, LA............. Sugarcane bagasse. 0.05 2006 Bio.
Verenium........................ Jennings, LA............. Sugarcane bagasse, 1.50 Feb-09 Bio.
wood, energy cane.
Western Biomass Energy LLC. Upton, WY................ Wood waste 1.50 2007 Bio.
(WBE). (softwood).
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Cello Energy.................... Bay Minette, AL.......... Wood chips, hay... 20.00 Dec-08 CatDep.
Bell BioEnergy.................. Fort Stewart, GA......... Wood chips........ 0.01 Dec-08 Bact.
----------------------------------------------------------------------------------------------------------------
Total Existing Production Capacity 23 MGY
----------------------------------------------------------------------------------------------------------------
\a\ Bio = biochemical pre-treatment, Therm = thermochemical conversion, CatDep = catalytic depolymerization,
Bact = involves the use of live bacteria to break down biomass for cellulosic diesel production.
\b\ Cellulosic pilot plant is collocated with a corn ethanol plant.
[[Page 24989]]
To date, the majority of cellulosic ethanol research has focused on
biochemical pre-treatment technologies, i.e., the use of acids and/or
enzymes to break down cellulosic materials into fermentable sugars.
However, there are a growing number of companies investigating the
thermochemical pathway which involves gasification of biomass into a
synthesis gas or pyrolysis of biomass into a bio-crude oil for
processing. Cellulosic diesel can also be made from thermochemical as
well as other processes. Many companies are also researching the
potential of co-firing biomass to produce plant energy in addition to
biofuels. For more on cellulosic biofuel processing technologies, refer
to Section 1.4.3 of the DRIA.
In addition to the existing facilities in Table V.B.2-1, our April
2009 industry assessment suggests that there are currently three
cellulosic ethanol plants under construction in the United States. Like
the existing plants, two are pilot-level facilities that are still
working towards proving their conversion technologies. However, Range
Fuels, a company that received $76 million from DOE and an $80 loan
guarantee from USDA to build one of the first commercial-scale
cellulosic ethanol plants in the U.S., is currently building a 40
million gallon per year plant in Soperton, GA.\82\ At this time, the
company is just working on the initial 10 million gallon per year
phase. Bell Bioenergy, a company that received $7.5 million in funding
from the Department of Defense to convert biomass into cellulosic
diesel using live bacteria, also has six pilot plants under
construction in various locations through the country. A summary of
these nine cellulosic biofuel plants, totaling over 10 million gallons
of annual production capacity, is presented in Table V.B.2-2.
---------------------------------------------------------------------------
\82\ Range Fuels' ultimate goal is to expand the Soperton, GA
facility to produce 100 million gallons of cellulosic ethanol per
year.
---------------------------------------------------------------------------
As shown in Tables V.B.2-1 and V.B.2-2, unlike corn ethanol
production, which is primarily located in the Midwest near the Corn
Belt, cellulosic biofuel production is spread throughout the country.
The geographic distribution of plants is due to the wide variety and
availability of cellulosic feedstocks. Corn stover is found primarily
in the Midwest, while the Pacific Northwest, the Northeast, and the
Southeast all have forestry residues. Some southern states have access
to sugarcane bagasse and citrus waste while MSW and C&D debris are
available in highly populated areas throughout the country. For more
information on cellulosic feedstock availability, refer to Section
1.1.2 of the DRIA.
Table V.B.2-2--Cellulosic Biofuel Plants Currently Under Construction
----------------------------------------------------------------------------------------------------------------
Prod Est.
Company plant name Location Feedstocks cap op. Conv. tech.
(MGY) date. \a\
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
Coskata......................... Madison, PA.............. MSW, natural gas, 0.04 Jul-09 Therm.
woodchips,
bagasse,
switchgrass.
DuPont Dansico Cellulosic Vonore, TN............... Corn cobs then 0.25 Dec-09 Bio.
Ethanol (DDCE). switchgrass.
Range Fuels \b\................. Soperton, GA............. Wood waste, 10.00 Dec-09 Therm.
switchgrass.
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Bell Bio-Energy................. Fort Lewis, WA........... Cellulose......... 0.01 2009 Bact.
Bell Bio-Energy................. Fort Drum, NY............ Cellulose......... 0.01 2009 Bact.
Bell Bio-Energy................. Fort AP Hill, VA......... Cellulose......... 0.01 2009 Bact.
Bell Bio-Energy................. Fort Bragg, NC........... Cellulose......... 0.01 2009 Bact.
Bell Bio-Energy................. Fort Benning, GA......... Cellulose......... 0.01 2009 Bact.
Bell Bio-Energy................. San Pedro, CA............ Cellulose......... 0.01 2009 Bact.
----------------------------------------------------------------------------------------------------------------
Total Under Construction Production Capacity 10 MGY
----------------------------------------------------------------------------------------------------------------
\a\ Bio = biochemical pre-treatment, Therm = thermochemical conversion, Bact = involves the use of live bacteria
to break down biomass for cellulosic diesel production.
\b\ The first 10 MGY phase is currently under construction in Soperton, GA. Once this second 30 MGY phase is
added, the plant will be capable of producing 40 MGY of cellulosic ethanol.
Increased public interest, government support, technological
advancement, and the recently-enacted EISA have helped spur many plans
for new cellulosic biofuel plants. Although more and more plants are
being announced, most are limited in size and contingent upon
technology breakthroughs and efficiency improvements at the pilot or
demonstration level. Additionally, because cellulosic biofuel
production has not yet been proven on the commercial level, financing
of these projects has primarily been through venture capital and
similar funding mechanisms, as opposed to conventional bank loans.
Consequently, recently-announced Federal grant and loan guarantee
programs may serve as a significant asset to the cellulosic biofuel
industry in this area. In February 2007, DOE announced that it would
invest up to $385 million in six commercial-scale ethanol projects over
the next four years. Since the announcement, two of the companies have
forfeited their funding. Iogen has decided to locate its first
commercial-scale plant in Canada and Alico has discontinued plans to
produce ethanol all together. The four remaining ``pioneer'' plants
(including Range Fuels) hold promise and could very well be some of the
first plants to demonstrate the commercial-scale viability of
cellulosic ethanol production. However, there is still more to be
learned at the pilot level. Although technologies needed to convert
[[Page 24990]]
cellulosic feedstocks into ethanol (and diesel) are becoming more and
more understood, there are still a number of efficiency improvements
that need to occur before cellulosic biofuels can compete in today's
marketplace.
In May 2007, DOE announced that it would provide up to $200 million
to help fund small-scale cellulosic biorefineries experimenting with
novel processing technologies that could later be expanded to
commercial production facilities. Four recipients were announced in
January 2008 and three more were announced in April 2008. Three months
later, DOE announced that it would provide $40 million more to help
fund two additional small-scale plants. Of the nine announced small-
scale plants, seven were pursuing cellulosic ethanol production
(including Verenium Corp.) and two are pursuing cellulosic diesel
production. However, Lignol Innovations, recently suspended plans to
build a 2.5 million gallon per year cellulosic ethanol plant in Grand
Junction, CO due to market uncertainty.
The Department of Energy has also introduced a loan guarantee
program to help reduce risk and spur investment in projects that employ
new, clean energy technologies. In October 2007, DOE issued final
regulations and invited 16 project sponsors who submitted pre-
applications to submit full applications for loan guarantees. Of those
who were invited to participate, five were pursuing cellulosic biofuel
production. However, only three companies appear to still be
eligible.\83\ Of the three remaining companies, two are pursuing
cellulosic ethanol production (and are also DOE grant recipients) and
one is pursuing cellulosic diesel production. The U.S. Department of
Agriculture is also providing an $80 million loan guarantee to Range
Fuels to help support construction of its 40 million-gallon-per-year
cellulosic ethanol plant in Soperton, GA. For more on information on
Federal support for biofuel production, refer to Section 1.5.3 of the
DRIA.
---------------------------------------------------------------------------
\83\ Iogen and Alico have also forfeited a potential loan
guarantee from DOE.
---------------------------------------------------------------------------
In addition to the companies receiving government funding, there
are a growing number of privately-funded companies (including Cello
Energy) with plans to build more cellulosic biofuel plants in the
United States. These facilities range in size from pilot- and
demonstration-level plants (similar to those currently operational or
under construction), to small commercial plants (similar to the four
commercial-scale plants receiving DOE funding), to large commercial
plants (similar in size to an average corn ethanol plant). These
projects are also at various stages of planning. According to our April
2009 industry assessment, 11 plants are currently at advanced stages of
planning and likely to go online in the near future. Along with those
plants currently operational or under construction, we believe that
these facilities will enable the U.S. to meet the 100 million gallon
cellulosic biofuel standard in 2010. For a summary of the plants and
their respective projected contributions, refer to Table V.B.2-3 below.
For a greater discussion on these and other cellulosic biofuel
projects, refer to Section 1.5.3.1 of the DRIA.
Table V.B.2-3--Projected Cellulosic Biofuel Production in 2010
----------------------------------------------------------------------------------------------------------------
Est 2010
Est. 2010 ETOH-
Company or organization name Location Prod cap Est. op. date million equiv.
(MGY) gallons million
gallons
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
BPI & Universal Entech............ Phoenix, AZ.......... 0.01 Online.............. 0.01 0.01
POET Project Bell................. Scotland, SD......... 0.02 Online.............. 0.02 0.02
Abengoa Bioenergy Corporation..... York, NE............. 0.02 Online.............. 0.02 0.02
Bioengineering Resources, Inc. Fayetteville, AK..... 0.04 Online.............. 0.04 0.04
(BRI).
Verenium.......................... Jennings, LA......... 0.05 Online.............. 0.05 0.05
Gulf Coast Energy................. Livingston, AL....... 0.20 Online.............. 0.20 0.20
Mascoma Corporation............... Rome, NY............. 0.20 Online.............. 0.20 0.20
Verenium.......................... Jennings, LA......... 1.50 Online.............. 1.50 1.50
Western Biomass Energy, LLC. (WBE) Upton, WY............ 1.50 Online.............. 1.50 1.50
Coskata........................... Madison, PA.......... 0.04 Jul-09.............. 0.04 0.04
DuPont Dansico Cellulosic Ethanol Vonore, TN........... 0.25 Dec-09.............. 0.25 0.25
(DDCE).
Range Fuels....................... Soperton, GA......... 10.0 Dec-09.............. 10.0 10.0
Ecofin/Alltech.................... Springfield, KY...... 1.30 2010................ 0.65 0.65
Fulcrum Bioenergy................. Storey County, NV.... 10.50 2010................ 5.25 5.25
ICM Inc........................... St. Joseph, MO....... 1.50 2010................ 0.75 0.75
RSE Pulp & Chemical............... Old Town, ME......... 2.20 2010................ 1.10 1.10
ZeaChem........................... Boardman, OR......... 1.50 2010................ 0.75 0.75
ClearFuels Technology............. Kauai, HI............ 1.50 End of 2010......... 0.38 0.38
Southeast Renewable Fuels LLC..... Clewiston, FL........ 20.00 End of 2010......... 5.00 5.00
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Cello Energy...................... Bay Minette, AL...... 20.00 Online.............. 20.00 32.00
Bell Bio-Energy................... Fort Stewart, GA..... 0.01 2008................ 0.01 0.01
Bell Bio-Energy................... Fort Lewis, WA....... 0.01 2009................ 0.01 0.01
Bell Bio-Energy................... Fort Drum, NY........ 0.01 2009................ 0.01 0.01
Bell Bio-Energy................... Fort AP Hill, VA..... 0.01 2009................ 0.01 0.01
Bell Bio-Energy................... Fort Bragg, NC....... 0.01 2009................ 0.01 0.01
Bell Bio-Energy................... Fort Benning, GA..... 0.01 2009................ 0.01 0.01
Bell Bio-Energy................... San Pedro, CA........ 0.01 2009................ 0.01 0.01
[[Page 24991]]
Cello Energy...................... TBD (AL)............. 50.00 2010................ 16.67 26.67
Cello Energy...................... TBD (AL)............. 50.00 2010................ 16.67 26.67
Cello Energy...................... TBD (GA)............. 50.00 2010................ 16.67 26.67
Flambeau River Biofuels........... Park Falls, WI....... 6.00 2010................ 3.00 4.80
-----------------------------------------------------------------------------
Total 2010 Production Forecast ..................... ......... .................... 100.74 144.57
----------------------------------------------------------------------------------------------------------------
b. Federal/State Production Incentives
In addition to helping fund a series of small-scale cellulosic
biofuel plants, the Department of Energy, along with the U.S.
Department of Agriculture (USDA), is also helping to fund critical
research to help make cellulosic biofuel production more commercially
viable. In March 2007, DOE awarded $23 million in grants to four
companies and one university to develop more efficient microbes for
ethanol refining. In June 2007, DOE and USDA awarded $8.3 million to 10
universities, laboratories, and research centers to conduct genomics
research on woody plant tissue for bioenergy. Later that same month,
DOE announced plans to spend $375 million to build three bioenergy
research centers dedicated to accelerating research and development of
cellulosic ethanol and other biofuels. The centers, which will each
focus on different feedstocks and biological research challenges, will
be located in Oak Ridge, TN, Madison, WI, and Berkeley, CA. In December
2007, DOE awarded $7.7 million to one company, one university, and two
research centers to demonstrate the thermochemical conversion process
of turning grasses, stover, and other cellulosic materials into
biofuel. In February 2008, DOE awarded another $33.8 million to three
companies and one research center to support the development of
commercially-viable enzymes to support cellulose hydrolysis, a critical
step in the biochemical breakdown of cellulosic feedstocks. Finally, in
March 2008, DOE and USDA awarded $18 million to 18 universities and
research institutes to conduct research and development of biomass-
based products, biofuels, bioenergy, and related processes. Since 2007,
DOE has announced more than $1 billion and since 2006, USDA has
invested almost $600 million for the research, development, and
demonstration of new biofuel technology.
Numerous states are also offering grants, tax incentives, and loan
guarantees to help encourage biofuel production. The majority of
efforts are centered on expanding ethanol production, and more
recently, cellulosic ethanol production.\84\ According to a July 2008
assessment of DOE's Energy Efficiency and Renewable Energy (EERE) Web
site,\85\ 33 states currently offer some form of ethanol production
incentive. The incentives range from support for ethanol producers to
support for research and development companies to support for feedstock
suppliers. Kansas, Maryland, and South Carolina each offer specific
incentives towards cellulosic ethanol production. Kansas offers revenue
bonds through the Kansas Development Finance Authority to help fund
construction or expansion of a cellulosic ethanol plant. Additionally,
these newly-built or expanded facilities are exempt from state property
tax for 10 years. Maryland offers a credit towards state income tax for
10% of cellulosic ethanol research and development expenses. They also
have a $0.20 per gallon production credit for cellulosic ethanol. South
Carolina gives a $0.30 per gallon production credit to cellulosic
ethanol producers that meet certain requirements.
---------------------------------------------------------------------------
\84\ For more on state-level biodiesel production incentives,
refer to Section 1.5.4 of the DRIA.
\85\ The database of ethanol incentives and laws by state is
available at: http://www.eere.energy.gov/afdc/ethanol/incentives_laws.html.
---------------------------------------------------------------------------
In addition to individual state incentives, a group of states in
the Midwest have joined together to pursue ethanol and other biofuel
production and usage goals as part of the Midwest Energy Security and
Climate Stewardship Platform.\86\ As of June 2008, Indiana, Iowa,
Kansas, Michigan, Minnesota, North Dakota, Ohio, South Dakota, and
Wisconsin had all committed to these goals which emphasize energy
independence through the growth of cellulosic ethanol production and
availability of E85. The Platform goals are to produce cellulosic
ethanol on a commercial level by 2012 and to have E85 offered at one-
third of refueling stations by 2025. They also want to reduce the
energy intensity of ethanol production and supply 50% of their
transportation fuel needs by regionally produced biofuels by 2025.
---------------------------------------------------------------------------
\86\ Midwest Governors Association, ``Energy Security and
Climate Stewardship Platform for the Midwest 2007'' (http://www.midwesterngovernors.org/resolutions/Platform.pdf)
---------------------------------------------------------------------------
Finally, the passage of the Food, Conservation, and Energy Act of
2008 (also known as the ``2008 Farm Bill'') is also helping to spur
cellulosic ethanol production and use.\87\ The 2008 Farm Bill modified
the existing $0.51 per gallon alcohol blender credit to give preference
to ethanol and other biofuels produced from cellulosic feedstocks. Corn
ethanol now receives a reduced credit of $0.45/gal while cellulosic
biofuel earns a credit of $1.01/gal.\88\ The 2008 Farm Bill also has
provisions that enable USDA to assist with the commercialization of
second-generation biofuels. Section 9003 authorizes loan guarantees for
the development, construction and retrofitting of commercial scale
biorefineries. Section 9004 provides payments to biorefineries to
replace fossil fuels with renewable biomass. Section 9005 provides
payments to producers to support and ensure production of advanced
biofuels. And finally, Section 9008 provides competitive grants,
contracts and financial assistance to enable eligible entities to carry
out research, development, and demonstration of biofuels and biomass-
based based products. For more information on the Federal and state
production incentives outlined in this subsection, refer to Section
1.5.3.2 of the DRIA.
---------------------------------------------------------------------------
\87\ The Food, Conservation, and Energy Act of 2008 (http://www.usda.gov/documents/Bill_6124.pdf)
\88\ Refer to Part II, Subparts A and B (Sections 15321 and
15331).
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c. Feedstock Availability
A wide variety of feedstocks can be used for cellulosic ethanol
production, including: Agricultural residues,
[[Page 24992]]
forestry biomass, municipal solid waste, construction and demolition
waste, and energy crops. These feedstocks are much more difficult to
convert into ethanol than traditional starch/corn crops or at least
require new and different processes because of the more complex
structure of cellulosic material.
One potential barrier to commercially viable cellulosic biofuel
production is high feedstock cost. As such, fuel producers will seek to
acquire inexpensive feedstocks in sufficient quantities to lower their
production costs and the risk of feedstock supply shortages. At least
initially, the focus will be on feedstocks that are readily available,
already produced or collected for other reasons, and even waste biomass
which currently incurs a disposal fee. Consequently, initial volumes of
cellulosic biofuels may benefit from low-cost feedstocks. However, to
reach 16 Bgal will likely require reliance on more expensive feedstock
sources purposely grown and or harvested for conversion into cellulosic
biofuel.
To determine the likely cellulosic feedstocks for production of 16
billion gallons cellulosic biofuel by 2022, we analyzed the data and
results from various sources. Sources include agricultural modeling
from the Forestry Agriculture Sector Optimization Model (FASOM) to
establish the most economical agriculture residues and energy crops
(see Section IX for more details on the FASOM), consultation with USDA-
Forestry Sector experts for forestry biomass supply curves, and
feedstock assessment estimates for urban waste.\89\
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\89\ It is important to note that our plant siting analysis for
cellulosic ethanol facilities used the most current version of
outputs from FASOM at the time, which was from April 2008. Since
then, FASOM has been updated to reflect better assumptions.
Therefore, the version used for the NPRM in Section IX on economic
impacts is slightly different than the one we used here. We do not
believe that the differences between the two versions are enough to
have a major impact on the plant siting analysis.
---------------------------------------------------------------------------
An important assumption in our analysis projecting which feedstocks
will be used for producing cellulosic ethanol is that an excess of
feedstock would have to be available for producing the biofuel. Banks
are anticipated to require excess feedstock supply as a safety factor
to ensure that the plant will have adequate feedstock available for the
plant, despite any feedstock emergency, such as a fire, drought,
infestation of pests etc. For our analysis we assumed that twice the
feedstock of MSW, C&D waste, and forest residue would have to be
available to justify the building of a cellulosic ethanol plant. For
corn stover, we assumed 50% more feedstock than necessary. We used a
lower safety factor for corn stover because it could be possible to
remove a larger percentage of the corn stover in any given year
(usually only 50% or less of corn stover is assumed to be sustainably
removed in any one year).\90\ As a result, our projected cellulosic
facilities only consume a portion of the total supply of feedstock
available. After a cellulosic facility is fully established and certain
risks are reduced, it is entirely possible that the facility may choose
to consume excess feedstock in order to expand production. In addition,
more facilities could potentially be built if financial investors
required less excess supply. Since we are assessing the impact of
producing 16 Bgal of cellulosic biofuel by 2022, this analysis does not
project the construction of more facilities or more feedstocks consumed
than necessary.
---------------------------------------------------------------------------
\90\ The FASOM results do not take into consideration these
feedstock safety margins. Safety margins were used, however, for the
plant siting analysis described in Section V.B.2.c.v.
---------------------------------------------------------------------------
Another assumption that we made is that if multiple feedstocks are
available in an area, each would be used as feedstocks for a
prospective cellulosic ethanol plant. For example, a particular area
might comprise a small or medium sized city, some forest and some
agricultural land. We would include the MSW and C&D wastes available
from the city along with the corn stover and forest residue for
projecting the feedstock that would be processed by the particular
cellulosic ethanol plant.
The following subsections describe the availability of various
cellulosic feedstocks and the estimated amounts from each feedstock
needed to meet the EISA requirement of 16 Bgal of cellulosic biofuel by
2022. Refer to Section V.B.2.c.iv for the summarized results of the
types and volumes of cellulosic feedstocks chosen based on our
analyses.
i Urban Waste
Cellulosic feedstocks available at the lowest cost to the ethanol
producer will likely be chosen first. This suggests that urban waste
which is already being gathered today and which incurs a fee for its
disposal may be among the first to be used. Urban wood wastes are used
in a variety of ways. Most commonly, wastes are ground into mulch,
dumped into land-fills, or incinerated with other municipal solid waste
(MSW) or construction and demolition (C&D) debris. Urban wood wastes
include a variety of wood resources such as wood-based municipal solid
waste and wood debris from construction and demolition.
MSW consists of paper, glass, metals, plastics, wood, yard
trimmings, food scraps, rubber, leather, textiles, etc. The portion of
MSW containing cellulosic material and typically the focus for biofuel
production is wood and yard trimmings. In addition, paper, which made
up approximately 34% of the total MSW generated in 2006, could
potentially be converted to cellulosic biofuel.\91\ Food scraps could
also be converted to cellulosic biofuel, however, it was noted by an
industry group that this feedstock could be more difficult to convert
to biofuel due to challenges with separation, storage, transport, and
degradation of the materials. Although recycling/recovery rates are
increasing over time, there appears to still be a large fraction of
biogenic material that ends up unused and in land-fills. C&D debris is
typically not available in wood waste assessments, although some have
estimated this feedstock based on population. In 1996, this was
estimated to be approximately 124 million metric tons of C&D
debris.\92\ Only a portion of this, however, would be made of woody
material. Utilization of such feedstocks could help generate energy or
biofuels for transportation. However, despite various assessments on
urban waste resources, there is still a general lack of reliable data
on delivered prices, issues of quality (potential for contamination),
and lack of understanding of potential competition with other
alternative uses (e.g. recycling, burning for electricity).
---------------------------------------------------------------------------
\91\ EPA. Municipal Solid Waste Generation, Recycling, and
Disposal in the United States: Facts and Figures for 2006.
\92\ Fehrs, J., ``Secondary Mill Residues and Urban Wood Waste
Quantities in the United States--Final Report,'' Northeast Regional
Biomass Program Washington, DC, December 1999.
---------------------------------------------------------------------------
We estimated that 42 million dry tons of MSW (wood and yard
trimmings & paper) and C&D wood waste could be available for producing
biofuels after factoring in several assumptions (e.g. percent
contamination, percent recovered or combusted for other uses, and
percent moisture).93 94 We assumed that approximately 25
million dry tons (of the total 42 million dry tons) would be used.
However, many areas of the U.S. (e.g. much of the Rocky Mountain
States) have such sparse resources that a MSW and C&D cellulosic
facility would not likely be justifiable. We did assume that in areas
with other
[[Page 24993]]
cellulosic feedstocks (forest and agricultural residue), that the MSW
would be used even if the MSW could not justify the installation of a
plant on its own. Therefore, we have estimated that urban waste could
help contribute to the production of approximately 2.2 billion gallons
of ethanol.\95\ A more detailed discussion on this analysis is included
in the DRIA Chapter 1. Subsequent to initiating our analysis, however,
we realized that the revised renewable biomass definition in the
statute may preclude the use of most MSW. See Section III.B.4 for a
discussion of renewable biomass. When the definition of renewable
biomass is finalized, it could preclude the use of some of the lowest
cost potential feedstocks, including waste paper and C&D waste, for use
in producing cellulosic biofuel for use toward the RFS2 standard. If
this is the case, then our FRM analysis will be adjusted to reflect
this.
---------------------------------------------------------------------------
\93\ Wiltsee, G., ``Urban Wood Waste Resource Assessment,''
NREL/SR-570-25918, National Renewable Energy Laboratory, November
1998.
\94\ Biocycle, ``The State of Garbage in America,'' Vol. 47, No.
4, 2006, p. 26.
\95\ Assuming 90 gal/dry ton ethanol conversion yield for urban
waste in 2022.
---------------------------------------------------------------------------
In addition to MSW and C&D waste generated from normal day-to-day
activities, there is also potential for renewable biomass to be
generated from natural disasters. This includes diseased trees, other
woody debris, and C&D debris. For instance, Hurricane Katrina was
estimated to have damaged approximately 320 million large trees.\96\
Katrina also generated over 100 million tons of residential debris, not
including the commercial sector. The material generated from these
situations could potentially be used to generate cellulosic biofuel.
While we acknowledge this material could provide a large source in the
short-term, natural disasters are highly variable, making it hard to
predict future volumes that could be generated. We seek comment on how
to take into account such estimates to be included in future feedstock
availability analyses.
---------------------------------------------------------------------------
\96\ Chambers, J., ``Hurricane Katrina's Carbon Footprint on
U.S. Gulf Coast Forests'' Science Vol. 318, 2007.
---------------------------------------------------------------------------
ii. Agricultural and Forestry Residues
The next category of feedstocks chosen will likely be those that
are readily produced but have not yet been commercially collected. This
includes both agricultural and forestry residues.
Agricultural residues are expected to play an important role early
on in the development of the cellulosic ethanol industry due to the
fact that they are already being grown. Agricultural crop residues are
biomass that remains in the field after the harvest of agricultural
crops. The most common residue types include corn stover (the stalks,
leaves, and/or cobs), straw from wheat, rice, barley, or oats, and
bagasse from sugarcane. The eight leading U.S. crops produce more than
500 million tons of residues each year, although only a fraction can be
used for fuel and/or energy production due to sustainability and
conservation constraints.\97\ Crop residues can be found all over the
United States, but are primarily concentrated in the Midwest since corn
stover accounts for half of all available agricultural residues.
---------------------------------------------------------------------------
\97\ Elbehri, Aziz. USDA, ERS. ``An Evaluation of the Economics
of Biomass Feedstocks: A Synthesis of the Literature. Prepared for
the Biomass Research and Development Board,'' 2007; Since 2007, a
final report has been released. Biomass Research and Development
Board, ``The Economics of Biomass Feedstocks in the United States: A
Review of the Literature,'' October 2008.
---------------------------------------------------------------------------
Agricultural residues play an important role in maintaining and
improving soil quality, protecting the soil surface from water and wind
erosion, helping to maintain nutrient levels, and protecting water
quality. Thus, collection and removal of agricultural residues must
take into account concerns about the potential for increased erosion,
reduced crop productivity, depletion of soil carbon and nutrients, and
water pollution. Sustainable removal rates for agricultural residues
have been estimated in various studies, many showing tremendous
variability due to local differences in soil and erosion conditions,
soil type, landscape (slope), tillage practices, crop rotation
managements, and the use of cover crops. One of the most recent studies
by top experts in the field showed that under current rotation and
tillage practices, about 30% of stover (about 59 million metric tons)
produced in the U.S. could be collected, taking into consideration
erosion, soil moisture concerns, and nutrient replacement costs.\98\
The same study showed that if farmers chose to convert to no-till corn
management and total stover production did not change, then
approximately 50% of stover (100 million metric tons) could be
collected without causing erosion to exceed the tolerable soil loss.
This study, however, did not consider possible soil carbon loss which
other studies indicate may be a greater constraint to environmentally
sustainable feedstock harvest than that needed to control water and
wind erosion.\99\ Experts agree that additional studies are needed to
further evaluate how soil carbon and other factors affect sustainable
removal rates. Despite unclear guidelines for sustainable removal rates
due to the uncertainties explained above, our agricultural modeling
analysis assumes that 0% of stover is removable for conventional tilled
lands, 35% of stover is removable for conservation tilled lands, and
50% is removable for no-till lands. In general, these removal
guidelines are appropriate only for the Midwest, where the majority of
corn is currently grown.
---------------------------------------------------------------------------
\98\ Graham, R.L., ``Current and Potential U.S. Corn Stover
Supplies,'' American Society of Agronomy 99:1-11, 2007.
\99\ Wilhelm, W.W. et. al., ``Corn Stover to Sustain Soil
Organic Carbon Further Constrains Biomass Supply,'' Agron. J.
99:1665-1667, 2007.
---------------------------------------------------------------------------
As already noted, removal rates will vary within regions due to
local differences. Given the current understanding of sustainable
removal rates, we believe that such assumptions are reasonably
justified. We invite comment on these assumptions. Based on our
research we also note that residue maintenance requirements for the
amount of biomass that must remain on the land to ensure soil quality
is another approach for modeling sustainable residue collection
quantities, therefore we also invite comment on this approach. This
approach would likely be more accurate for all landscapes as site
specific conditions such as soil type, topography, etc. could be taken
into account. This would prevent site specific soil erosion and soil
quality concerns that would inevitably exist when using average values
for residue removal rates across all soils and landscapes. At the time
of our analyses we had limited data on which to accurately apply this
approach and therefore assumed the removal guidelines based on tillage
practices. Refer to the Section 1.1 of the DRIA for more discussion on
sustainable removal rates.
Some of the challenges of relying on agricultural residues to
produce biofuels include the development of the technology and
infrastructure for the harvesting of biomass crops. For example, it may
be possible to reduce costs by harvesting the corn stover at the same
time that the corn is harvested, in a single pass operation, as opposed
to two separate harvests. In addition, because agricultural residues
are usually harvested only one time per year, but cellulosic ethanol
plants must receive the feedstock throughout the year, agricultural
residues would likely need to be stored at a secondary storage
facility. The transportation and storage issues and costs associated
with this secondary storage will add additional costs to using
agricultural residue as cellulosic plant feedstock. These significant
transportation and storage issues need to be resolved and the
infrastructure built before agricultural
[[Page 24994]]
residues can supply a steady stream of feedstock to the biorefinery. We
discuss these harvesting and storage challenges in Section 1.3 of the
DRIA.
Our agricultural modeling (FASOM) suggests that corn stover will
make up the majority of agricultural residues used by 2022 to meet the
EISA cellulosic biofuel standard (approximately 83 million dry tons
used to produce 7.8 billion gallons of cellulosic ethanol).\100\
Smaller contributions are expected to come from other crop residues,
including bagasse (1.2 Bgal ethanol) and sweet sorghum pulp (0.1 Bgal
ethanol).\101\ At the time of this proposal, FASOM was able to model
agricultural residues but not forestry biomass as potential feedstocks.
As a result, we relied on USDA-Forest Service (FS) for information on
the forestry sector.
---------------------------------------------------------------------------
\100\ Assuming 94 gal/dry ton ethanol conversion yield for corn
stover in 2022.
\101\ Bagasse is a byproduct of sugarcane crushing and not
technically an agricultural residue. Sweet sorghum pulp is also a
byproduct of sweet sorghum processing. We have included it under
this heading for simplification due to sugarcane being an
agricultural feedstock.
---------------------------------------------------------------------------
The U.S. has vast amounts of forest resources that could
potentially provide feedstock for the production of cellulosic biofuel.
One of the major sources of woody biomass could come from logging
residues. The U.S. timber industry harvests over 235 million dry tons
annually and produces large volumes of non-merchantable wood and
residues during the process.\102\ Logging residues are produced in
conventional harvest operations, forest management activities, and
clearing operations. In 2004, these operations generated approximately
67 million dry tons/year of forest residues that were left uncollected
at harvest sites.\103\ Other feedstocks include those from other
removal residues, thinnings from timberland, and primary mill residues.
---------------------------------------------------------------------------
\102\ Smith, W. Brad et. al., ``Forest Resources of the United
States, 2002 General Technical Report NC-241,'' St. Paul, MN: U.S.
Dept. of Agriculture, Forest Service, North Central Research
Station, 2004.
\103\ USDA-Forest Service. ``Timber Products Output Mapmaker
Version 1.0.'' 2004.
---------------------------------------------------------------------------
Harvesting of forestry residue and other woody material can be
conducted throughout the year. Thus, unlike agricultural residue which
must be moved to secondary storage, forest material could be ``stored
on the stump.'' Avoiding the need for secondary storage and the
transportation costs for moving the feedstock there potentially
provides a significant cost advantage for forest residue over
agricultural residue. This could allow forest residue to be transported
from further distances away from the cellulosic plant compared to
agricultural residue at the same feedstock price. Section 1.1 of the
DRIA further details some of challenges with using forestry biomass as
a feedstock.
EISA does not allow forestry material from national forests and
virgin forests that could be used to produce biofuels to count towards
the renewable fuels requirement under EISA. Therefore, we required
forestry residue estimates that excluded such material. Most recently,
the USDA-FS provided forestry biomass supply curves for various sources
(i.e., logging residues, other removal residues, thinnings from
timberland, etc.). This information suggested that a total of 76
million dry tons of forest material could be available for producing
biofuels (excluding forest biomass material contained in national
forests as required under EISA). However, much of the forest material
is in small pockets of forest which because of its regional low
density, could not help to justify the establishment of a cellulosic
ethanol plant. After conducting our feedstock availability analysis, we
estimated that approximately 44 million dry tons of forest material
could be used, which would make up approximately one fourth, or 3.8
billion gallons, of the 16 billion gallons of cellulosic biofuel
required to meet EISA.
iii Dedicated Energy Crops
While urban waste, agricultural residues, and forest residues will
likely be the first feedstocks used in the production of cellulosic
biofuel, there may be limitations to their use due to land availability
and sustainable removal rates. Energy crops which are not yet grown
commercially but have the potential for high yields and a series of
environmental benefits could help provide additional feedstocks in the
future. Dedicated energy crops are plant species grown specifically as
renewable fuel feedstocks. Various perennial plants have been
researched as potential dedicated feedstocks. These include
switchgrass, mixed prairie grasses, hybrid poplar, miscanthus, and
willow trees.
Perennials have several benefits over many major agricultural crops
(the majority of which are annual plants). First, energy crops based on
perennial species are grown from roots or rhizomes that remain in the
soil after harvests. This reduces annual field preparation and
fertilization costs. Second, perennial crops in temperate zones may
also have significantly higher total biomass yield per unit of land
area compared to annual species because of higher rates of net
photosynthetic CO2 fixation into sugars. Third, lower
fertilizer runoff, lower soil erosion, and increased habitat diversity
are also attributes that make perennial crops more attractive than
annual crops.\104\ Finally, energy crops tend to store more carbon in
the soil compared to agricultural crops such as corn.\105\
---------------------------------------------------------------------------
\104\ DOE., ``Breaking the Biological Barriers to Cellulosic
Ethanol: A Joint Research Agenda,'' 2006.
\105\ Tolbert, V.R., et al., ``Biomass Crop Production: Benefits
for Soil Quality and Carbon Sequestration,'' March 1999.
---------------------------------------------------------------------------
The introduction of dedicated energy crops could present some
potential risks, however. Dedicated energy crops for cellulosic
biofuels can be non-native to the region where their production is
proposed.\106\ As a result, these species may potentially escape
cultivation and damage surrounding ecosystems.\107\ In addition
breeding and genetic engineering to increase environmental tolerance,
increase harvestable biomass production, and enhance energy conversion
may have unexpected ecological consequences. To minimize such risks,
non-native species and non-wild-type native species (i.e. native
species after genetic modification) should be introduced in a
responsible manner and evaluated carefully in order to weigh the
potential risks against the benefits.
---------------------------------------------------------------------------
\106\ Lewandowski, I., J. M. O. Scurlock, E. Lindvall, and M.
Chistou, ``The development and current status of perennial
rhizomatous grasses as energy crops in the U.S. and Europe,''
Biomass Bioenergy 25:335-361, 2003.
\107\ The Council for Agricultural Science and Technology
(CAST), ``Biofuel Feedstocks: The Risk of Future Invasions,'' CAST
Commentary QTA2007-1. November 2007. Accessed at: http://pdf.cast-science.org/websiteUploads/publicationPDFs/Biofuels%20Commentary%20Web%20version%20with%20color%20%207927146.pdf
---------------------------------------------------------------------------
Currently, an energy crop receiving much attention is switchgrass.
Switchgrass has many qualities that make it a prime cellulosic
feedstock option. However, switchgrass and other energy crops are not
currently harvested on a large scale. Switchgrass would likely be grown
on a 10-year crop rotation basis, with harvest beginning in year 1 or
2, depending on location. Because switchgrass and other dedicated
energy crops would not be harvested annually, there will be some
economic challenges in terms of price forecasting and contracts.
Accordingly, 10- to 15-year arrangements may be needed to stabilize the
market for energy crops.\108\ Despite these challenges, dedicated
energy crops are still projected to be needed in 2022 in order to meet
the aggressive goal of 16 Bgal of
[[Page 24995]]
cellulosic biofuel by 2022 as outlined in EISA.
---------------------------------------------------------------------------
\108\ Zeman, N., ``Feedstock: Potential Players,'' Ethanol
Producer Magazine, October 2006.
---------------------------------------------------------------------------
Since energy crops are not being grown today to make fuels, their
production and use depends on the development of a successful strategy.
One issue is that if they were to be grown on farmland currently used
to grow crops, the growth of switchgrass would have an opportunity cost
associated with the loss of agricultural production. For this reason,
energy crops may instead be grown on more marginal farm land such as
fallow farmland and farmland which has been converted over to prairie
grass. A study by Stanford and the Carnegie Institution found that 58
million hectares (145 million acres) of abandoned farmland would
potentially be available for growing energy crops here in the U.S.\109\
However, they also concluded that this land is marginal in quality and
thus the production per acre would be much lower compared to prime farm
land. Additionally, a substantial amount of this abandoned farm land is
a part of the Conservation Reserve Program (CRP). The CRP is the U.S.
Department of Agriculture's voluntary program that was established by
the Food Security Act of 1985 to provide farmers with a dependable
source of income, reduce erosion on unused farmland, and serve to
preserve wildlife and water quality.\110\ A large portion of the 36
million acres in the CRP land is currently planted with switchgrass and
mixed prairie grasses.\111\ However, the 2008 Farm Bill capped the
number of CRP acres at 32 million acres for 2010-2012, and we expect
that some of the CRP acres that are not re-enrolled will go into crop
production. While it may be possible to use some of the CRP acres to
produce biofuels from switchgrass and prairie grass, the potential loss
of the wildlife habitat and water quality benefits of CRP land would
have to be weighed against the potential use for this land for growing
energy crops. Also, a significant portion of the CRP land is wetlands
and likely could not be used for growing energy crops without impacting
water quality and wildlife.
---------------------------------------------------------------------------
\109\ Campbell, J.E. at al., ``The global potential of bioenergy
on abandoned agriculture lands,'' Environ. Sci. Technology, 2008.
\110\ Charles, Dan; ``The CRP: Paying Farmers not to Farm,''
National Public Radio, May 5, 2008.
\111\ Farm Service Agency, ``Conservation Reserve Program,
Summary and Enrollment Statistics FY2006,'' May 2007.
---------------------------------------------------------------------------
In addition to estimating the extent that agricultural residues
might contribute to cellulosic ethanol production, FASOM also estimated
the contribution that energy crops might provide.\112\ FASOM covers all
cropland and pastureland in production in the 48 conterminous United
States, however it does not contain all categories of grassland and
rangeland captured in USDA's Major Land Use data sets. Therefore, it is
possible there is land appropriate for growing dedicated energy crops
that is not currently modeled in FASOM. Furthermore, we constrained
FASOM to be consistent with the 2008 Farm Bill and assumed 32 million
acres would stay in CRP.\113\ These constraints on land availability
may have contributed to the model choosing a substantial amount of
agricultural residues mostly as corn stover and a relatively small
portion of energy crops as being economically viable feedstocks. The
use of other models, such as USDA's Regional Environment and
Agriculture Programming (REAP) model and University of Tennessee's
POLYSYS model, have shown that the use of energy crops in order to meet
EISA may be more significant than our current FASOM modeling
results.\114\ As such, we plan to revisit these land availability
assumptions in order to arrive at a more consistent basis for the FRM.
We request comment on these assumptions, in addition to all the
cellulosic yield assumptions that are contained in DRIA Chapter 1.
---------------------------------------------------------------------------
\112\ Assuming 16 Bgal cellulosic biofuel total, 2.2 Bgal from
Urban Waste, and 3.8 Bgal from Forestry Biomass; 10 Bgal of
cellulosic biofuel for ag residues and/or energy crops would be
needed.
\113\ Beside the economic incentive of a farmer payment to keep
land in CRP, local environmental interests may also fight to
maintain CRP land for wildlife preservation. Also, we did not know
what portion of the CRP is wetlands which likely could not support
harvesting equipment.
\114\ Biomass Research and Development Initiative (BR&DI),
``Increasing Feedstock Production for Biofuels: Economic Drivers,
Environmental Implications, and the Role of Research,'' http://www.brdisolutions.com December 2008.
---------------------------------------------------------------------------
iv. Summary of Cellulosic Feedstocks for 2022
Table V.B.2-4 summarizes our internal estimate of cellulosic
feedstocks and their corresponding volume contribution to 16 billion
gallons cellulosic biofuel by 2022 for the purposes of our impacts
assessment.
Table V.B.2-4--Cellulosic Feedstocks Assumed To Meet EISA in 2022
------------------------------------------------------------------------
Volume
Feedstock (Bgal)
------------------------------------------------------------------------
Agricultural Residues........................................ 9.1
Corn Stover.............................................. 7.8
Sugarcane Bagasse........................................ 1.2
Sweet Sorghum Pulp....................................... 0.1
Forestry Biomass............................................. 3.8
Urban Waste.................................................. 2.2
Dedicated Energy Crops (Switchgrass)......................... 0.9
----------
Total................................................ 16.0
------------------------------------------------------------------------
v. Cellulosic Plant Siting
Future cellulosic biofuel plant siting was based on the types of
feedstocks that would be most economical as shown in Table V.B.2-4,
above. As cellulosic biofuel refineries will likely be located close to
biomass resources in order to take advantage of lower transportation
costs, we've assessed the potential areas in the U.S. that grow the
various feedstocks chosen. To do this, we used data on harvested acres
by county for crops that are currently grown today, such as corn stover
and sugarcane (for bagasse).\115\ In some cases, crops are not
currently grown, but have the potential to replace other crops or
pastureland (e.g. dedicated energy crops). We used the output from our
economic modeling (FASOM) to help us determine which types of land are
likely to be replaced by newly grown crops. For forestry biomass, USDA-
Forestry Service provided supply curve data by county showing the
available tons produced. Urban waste (MSW wood, paper, and C&D debris)
was estimated to be located near large population centers.
---------------------------------------------------------------------------
\115\ NASS database. http://www.nass.usda.gov/.
---------------------------------------------------------------------------
Using feedstock availability data by county/city, we located
potential cellulosic sites across the U.S. that could justify the
construction of a cellulosic plant facility. For more details on this
analysis, refer to Section 1.5 of the DRIA. Table V.B.2-5 shows the
volume of cellulosic facilities by feedstock by state projected for
2022. The total volumes given in Table V.B.2-5 match the total volumes
given in Table V.B.2-4 within a couple hundred million gallons. As
these differences are relatively small, we believe the cellulosic
facilities sited are a good estimate of potential locations.
[[Page 24996]]
Table V.B.2-5--Projected Cellulosic Ethanol Volumes by State
[Million gallons in 2022]
----------------------------------------------------------------------------------------------------------------
Agricultural Energy Urban
State Total residue crop waste Forestry
volume volume volume volume volume
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 532 0 0 140 392
Arkansas....................................... 298 0 0 0 298
California..................................... 450 0 0 221 229
Colorado....................................... 28 0 0 28 0
Florida........................................ 421 390 0 31 0
Georgia........................................ 437 0 0 67 370
Illinois....................................... 1,525 1,270 0 198 58
Indiana........................................ 1,109 948 0 101 60
Iowa........................................... 1,697 1,635 0 32 30
Kansas......................................... 310 250 0 29 32
Kentucky....................................... 70 70 0 0 0
Louisiana...................................... 1,001 590 0 103 308
Maine.......................................... 191 0 0 2 189
Michigan....................................... 505 283 0 171 51
Minnesota...................................... 876 750 0 50 76
Mississippi.................................... 214 0 0 22 192
Missouri....................................... 654 504 0 78 72
Montana........................................ 92 0 0 9 83
Nebraska....................................... 956 851 0 31 75
Nevada......................................... 17 0 0 17 0
New Hampshire.................................. 171 0 35 29 107
New York....................................... 72 0 0 72 0
North Carolina................................. 315 0 0 98 217
Ohio........................................... 598 410 0 156 32
Oklahoma....................................... 793 0 777 0 16
Oregon......................................... 244 0 0 44 200
Pennsylvania................................... 42 0 0 42 0
South Carolina................................. 213 0 0 57 156
South Dakota................................... 434 350 0 6 78
Tennessee...................................... 97 0 0 19 78
Texas.......................................... 576 300 0 131 145
Virginia....................................... 197 0 0 95 102
Washington..................................... 175 0 0 17 158
West Virginia.................................. 149 0 101 0 48
Wisconsin...................................... 581 432 0 43 106
----------------------------------------------------------------
Total Volume............................... 16,039 9,034 913 2,139 3,955
----------------------------------------------------------------------------------------------------------------
It is important to note, however, that there are many more factors
other than feedstock availability to consider when eventually siting a
plant. We have not taken into account, for example, water constraints,
availability of permits, and sufficient personnel for specific
locations. As many of the corn stover facilities are projected to be
located close to corn starch facilities, there is the potential for
competition for clean water supplies. Therefore, as more and more
facilities draw on limited resources, it may become apparent that
various locations are infeasible. Nevertheless, our plant siting
analysis provides a reasonable approximation for analysis purposes
since it is not intended to predict precisely where actual plants will
be located. Other work is currently being done that will help address
some of these issues, but at the time of this proposal, was not yet
available.\116\
---------------------------------------------------------------------------
\116\ USDA, WGA, Bioenergy Strategic Assessment project findings
upcoming as noted in report WGA. Transportation Fuels for the Future
Biofuels: Part I. 2008.
---------------------------------------------------------------------------
As we are projecting the location of cellulosic plants in 2022, it
is important to keep in mind the various uncertainties in the analysis.
For example, future analyses could determine better recommendations for
sustainable removal rates. In the case where lower removal rates are
recommended, agricultural residues may be more limited and could
require more growth in dedicated energy crops. Also, the feedstocks
could be processed in the field to a liquid by a pyrolysis process,
facilitating the ability to ship the preprocessed biomass to plants
located further away from the feedstock source. Given the information
we have to date, we believe our projected locations for cellulosic
facilities represent a reasonable forecast for estimating the impacts
of this rule.
3. Imported Ethanol
a. Historic World Ethanol Production and Consumption
Although ethanol can be used for multiple purposes (fuel,
industrial, and beverage), fuel ethanol is by far the largest market,
accounting for about two-thirds of the total world ethanol consumed.
According to forecasts, fuel ethanol might even exceed 80% of the
market share by the end of the decade.\117\ In 2008, the top three fuel
ethanol producers were the U.S., Brazil, and the European Union (EU),
producing 9.0, 6.5, and 0.7 billion gallons, respectively.\118\ Other
countries that have produced ethanol include
[[Page 24997]]
China, Canada, Thailand, Colombia, and India.
---------------------------------------------------------------------------
\117\ F.O. Licht., ``World Ethanol Markets: The Outlook to
2015'', 2006, pg. 21.
\118\ Renewable Fuels Association (RFA), ``2007 World Fuel
Ethanol Production,'' http://www.ethanolrfa.org/industry/statistics/#E, March 31, 2009.
---------------------------------------------------------------------------
Consumption of fuel ethanol, like production, is also dominated by
the United States and Brazil. The U.S. dominates world fuel ethanol
consumption, with 9.6 billion gallons consumed in 2008 (domestic
production plus imports).\119\ Brazil is second in consumption, with
about 4.9 billion gallons projected to be consumed in 2007/2008.\120\
The EU is also a significant consumer of ethanol; however, consumption
for the EU countries was only approximately 0.7 billion gallons in
2007.\121\
---------------------------------------------------------------------------
\119\ Ibid.
\120\ UNICA, ``Sugarcane Industry in Brazil: Ethanol Sugar,
Bioelectricity'' Brochure, 2008.
\121\ European Bioethanol Fuel Association (eBio), ``The EU
Market: Production and Consumption,'' http://www.ebio.org/EUmarket.php, March 31, 2009.
---------------------------------------------------------------------------
b. Historic/Current Domestic Imports
Ethanol imports have traditionally played a relatively small role
in the U.S. transportation fuel market due to historically low crude
prices and the tariff on imported ethanol. While low crude prices made
it difficult for both domestic and imported ethanol to compete with
gasoline, the addition of the federal excise tax credit made it
possible for domestic ethanol to be economically competitive.
Between 2000 and 2003, the total volume of fuel ethanol imports
into the United States remained relatively stable at 46-68 million
gallons.\122\ During this period of time, mostly Brazilian-based
ethanol entered the U.S. primarily through the Caribbean Basin
Initiative (CBI) countries where it could avoid the tariff. From 2004-
2005, with rising crude oil prices, most estimates show U.S. fuel
ethanol imports increased slightly to 135-164 million gallons, or about
4% of the total U.S. fuel ethanol consumption (3.5 to 4.0 billion
gallons). The volume of imports rose dramatically in 2006 to 654-720
million gallons, or about 13% of the 2006 total ethanol consumption of
5.4 billion gallons. The largest volume of imports in 2006 was from
direct Brazilian imports. This increase in ethanol imports was mainly
due to the withdrawal of MTBE from the fuel pool which increased the
price of ethanol. MTBE was used in gasoline to fulfill the oxygenate
requirements set by Congress in the 1990 Clean Air Act Amendments.
EPAct further accelerated the withdrawal of MTBE because gasoline
marketers were no longer required to use an oxygenate and gasoline
marketers did not receive the MTBE liability protection that they had
petitioned for. Refiners responded by removing MTBE and replacing its
use with ethanol. As a result, the demand for ethanol increased at
unprecedented rates as most refiners replaced MTBE with ethanol. The
dramatic increase in crude oil costs at this time also made ethanol
more economical by comparison.
---------------------------------------------------------------------------
\122\ Values given report USITC and RFA data, however, EIA
reports slightly lower numbers prior to 2004.
---------------------------------------------------------------------------
By the end of 2006, almost all MTBE was phased out of gasoline.
However, crude oil prices remained high, allowing ethanol imports to
the U.S. to remain economical in comparison to the past. Although not
as high as the volume of ethanol imported in 2006, the U.S. continued
to import ethanol in 2007 (425-450 million gallons). In 2008, the U.S.
imported 519-556 million gallons.\123\ As the data show, the volume of
imported ethanol can fluctuate greatly. By looking at historical import
data it is difficult to project the potential volume of future imports
to the U.S. Rather, it is necessary to assess future import potential
by analyzing the major players for foreign biofuels production and
consumption.
---------------------------------------------------------------------------
\123\ USITC and EIA import data reported.
---------------------------------------------------------------------------
c. Projected Domestic Imports
In our assessment of foreign ethanol production and consumption, we
analyzed the following countries or group of countries: Brazil, the EU,
Japan, India, and China. Our analyses indicate that Brazil would likely
be the only nation able to supply any meaningful amount of ethanol to
the U.S. in the future. Depending on whether the mandates and goals of
the EU, Japan, India, and China are enacted or met in the future, it is
likely that this group of countries would consume any growth in their
own production and be net importers of ethanol, thus competing with the
U.S. for Brazilian ethanol exports.
Brazil is expected to supply the majority of future ethanol demand
and to expand their capacity for several reasons. First, Brazil has
over 30 years experience in developing the research and technologies
for producing sugarcane ethanol. As a result, Brazilians have been able
to improve agricultural and conversion processes so that sugarcane
ethanol is currently the least costly method for producing biofuels.
See Section VIII for further discussion on the production costs for
sugarcane ethanol.
Second, it is believed that domestic demand for ethanol in Brazil
will begin to slow as most of the national fleet of vehicles will have
transitioned to flex-fuel within the next few years.\124\ Thus, as
domestic demand begins to level off, some experts see a significant
possibility that exports will become more relevant in market share
terms.
---------------------------------------------------------------------------
\124\ Agra FNP, ``Sugar and Ethanol in Brazil: A Study of the
Brazilian Sugar Cane, Sugar and Ethanol Industries,'' 2007.
---------------------------------------------------------------------------
Lastly, Brazil has large land areas for potential expansion for
sugarcane. A study commissioned by the Brazilian government produced an
analysis in which Brazil's arable land was evaluated for its
suitability for cane.\125\ Setting aside areas protected by
environmental regulations and those with a slope greater than 12%
(those not suitable for mechanized farming), tripling ethanol
production (a goal set by the Brazilian government by 2020) would
require only an additional 14 million acres. This additional acreage
would only be about 2% of suitable land for sugarcane production. Refer
to Section 1.5 of the DRIA for more details.
---------------------------------------------------------------------------
\125\ CGEE, ABDI, Unicamp, and NIPE, Scaling Up the Ethanol
Program in Brazil, n.d. as quoted in Rothkopf, Garten, ``A Blueprint
for Green Energy in the Americas,'' 2006.
---------------------------------------------------------------------------
Although Brazil is in an excellent position to help meet the
growing global demand for ethanol, several constraints could limit the
expansion of ethanol production. As Brazil's government has adopted
plans to meet global demand by tripling production by 2020,\126\ this
would mean a total capacity of about 12.7 billion gallons, to be
achieved through a combination of efficiency gains, greenfield
projects, and infrastructure expansions. Estimates for the investment
required tend to range from $2 to $4 billion a year.\127\ In addition,
Brazil will need to improve its current ethanol infrastructure (i.e.
improvements in power, transportation, storage, distribution logistics,
and communications). It is estimated that Brazil will need to invest $1
billion each year for the next 15 years in infrastructure to keep pace
with capacity expansion and export demand.\128\ Refer to Section 1.5 of
the DRIA for further details on the improvements needed for Brazil to
increase ethanol production capacity.
---------------------------------------------------------------------------
\126\ Rothkopf, Garten, ``A Blueprint for Green Energy in the
Americas,'' 2006.
\127\ Ibid.
\128\ Ibid.
---------------------------------------------------------------------------
Due to uncertainties in the future demand for ethanol domestically
and internationally as well as uncertainties in the actual investments
made in the Brazilian ethanol industry, there appears to be a wide
range of Brazilian production and domestic consumption estimates. The
most current and complete estimates indicate that total
[[Page 24998]]
Brazilian ethanol exports will likely reach 3.8-4.2 billion gallons by
2022.129 130 131 As this volume of ethanol export is
available to countries around the world, only a portion of this will be
available exclusively to the United States. If the balance of the EISA
advanced biofuel requirement not met with cellulosic biofuel and
biomass-based diesel were to be met with imported sugarcane ethanol
alone, it would require 3.2 billion gallons (see Table V.A.2-1), or
approximately 80% of total Brazilian ethanol export estimates.
---------------------------------------------------------------------------
\129\ EPE, ``Plano Nacional de Energia 2030,'' Presentation from
Mauricio Tolmasquim, 2007.
\130\ UNICA, ``Sugarcane Industry in Brazil: Ethanol, Sugar,
Bioelectricity,'' 2008.
\131\ USEPA International Visitors Program Meeting October 30,
2007, correspondence with Mr. Rodrigues, Technical Director from
UNICA Sao Paulo Sugarcane Agro-industry Union, stated approximately
3.7 billion gallons probable by 2017/2020; Consistent with brochure
``Sugarcane Industry in Brazil: Ethanol Sugar, Bioelectricity'' from
UNICA (3.25 Bgal export in 2015 and 4.15 Bgal export in 2020).
---------------------------------------------------------------------------
The amount of Brazilian ethanol available for shipment to the U.S.
will be dependent on the biofuels mandates and goals set by other
foreign countries (i.e., the EU, Japan, India, and China) in addition
to U.S. policies to promote the use of renewable fuels. Our estimates
show that there could be a potential demand for imported ethanol of
4.6-14.6 billion gallons by 2020/2022 from these countries. This is due
to the fact that some countries are unable to produce large volumes of
ethanol because of land constraints or low production capacity. As
such, foreign countries may have limited domestic biofuel production
capability and may therefore require importation of biofuels in order
to meet their mandates and goals. Refer to Section 1.5 of the DRIA for
further details. Therefore, if other foreign country mandates and goals
are to be met, then Brazil may need to either increase production much
more than its government projects or export less ethanol to the U.S.
This suggests that the U.S. may be competing for Brazilian ethanol
exports if supplies are limited in the future. For our analysis we
assumed that the U.S. would consume the majority of Brazilian exports
(i.e. 80% of export estimates in 2022). This is aggressive, yet within
the bounds of reason, therefore, we have made this simplifying
assumption for the purposes of further analysis. We seek comment on the
legitimacy of this assumption given the ethanol export deals and
commitments that Brazil has made or may potentially make with other
nations in the future.
Generally speaking, Brazilian ethanol exporters will seek routes to
countries with the lowest transportation costs, taxes, and tariffs.
With respect to the U.S., the most likely route is through the
Caribbean Basin Initiative (CBI).\132\ Brazilian ethanol entering the
U.S. through the CBI countries is not currently subject to the 54 cent
imported ethanol tariff and yet receives the 45 cent ethanol blender
tax subsidy. Due to the economic incentive of transporting ethanol
through the CBI, we expect the majority of the tariff rate quota (TRQ)
to be met or exceeded, perhaps 90% or more. The TRQ is set each year as
7% of the total domestic ethanol consumed in the prior year. If we
assume that 90% of the TRQ is met and that total domestic ethanol (corn
and cellulosic ethanol) consumed in the prior year was 28.5 Bgal, then
approximately 1.8 Bgal of ethanol could enter the U.S. through CBI
countries. The rest of the Brazilian ethanol exports not entering the
CBI will compete on the open market with the rest of the world
demanding some portion of direct Brazilian ethanol. We calculated the
amount of direct Brazilian ethanol exports in 2022 to the U.S. as the
total imported ethanol required (3.14 billion gallons) to meet the RFS2
volume requirements subtracted by imported ethanol from CBI countries
(1.8 billion gallons), or equal to 1.34 billion gallons.
---------------------------------------------------------------------------
\132\ Other preferential trade agreements include the North
American Free Trade Agreement (NAFTA) which permits tariff-free
ethanol imports from Canada and Mexico and the Andean Trade
Promotion and Drug Eradication Act (ATPDEA) which allows the
countries of Columbia, Ecuador, Bolivia, and Peru to import ethanol
duty-free. Currently, these countries export or produce relatively
small amounts of ethanol, and thus we have not assumed that the U.S.
will receive any substantial amounts from these countries in the
future for our analyses.
---------------------------------------------------------------------------
In the past, companies have also avoided the ethanol import tariff
through a duty drawback.\133\ The drawback is a loophole in the tax
rules which allowed companies to import ethanol and then receive a
rebate on taxes paid on the ethanol when jet fuel is sold for export
within three years. The drawback considered ethanol and jet fuel as
similar commodities (finished petroleum derivatives).134 135
Most recently, however, Senate Representative Charles Grassley from
Iowa included a provision into the Farm Bill of 2008 that ended such
refunds. The provision states that ``any duty paid under subheading
9901.00.50 of the Harmonized Tariff Schedule of the United States on
imports of ethyl alcohol or a mixture of ethyl alcohol may not be
refunded if the exported article upon which a drawback claim is based
does not contain ethyl alcohol or a mixture of ethyl alcohol.'' \136\
The provision is effective on or after October 1, 2008 and companies
have until October 1, 2010 to apply for a duty drawback on prior
transactions. With the loophole closed, it is anticipated that there
may be less ethanol directly exported from Brazil in the future.\137\
---------------------------------------------------------------------------
\133\ Rapoza, Kenneth, ``UPDATE: Tax Loophole Helps US Import
Ethanol `Duty Free'--ED&F,'' INO News, Dow Jones Newswires, March
2008. http://news.ino.com/.
\134\ Peter Rhode, ``Senate Finance May Take Up Drawback
Loophole As Part of Energy Bill,'' EnergyWashington Week, April 18,
2007. As sited in Yacobucci, Brent, ``Ethanol Imports and the
Caribbean Basin Initiative,'' CRS Report for Congress, Order Code
RS21930, Updated March 18, 2008.
\135\ Perkins, Jerry, ``BRAZIL: Loophole Hurt U.S. Ethanol
Prices,'' DesMoinesRegister.com, October 18, 2007.
\136\ Public Law Version 6124 of the Farm Bill. 2008. http://www.usda.gov/documents/Bill_6124.pdf.
\137\ Lundell, Drake, ``Brazilian Ethanol Export Surge to End;
U.S. Customs Loophole Closed Oct. 1,'' Ethanol and Biodiesel News,
Issue 45, November 4, 2008.
---------------------------------------------------------------------------
For our distribution and air quality analyses, we had to make a
determination as to where the projected imported ethanol would likely
enter the United States. To do so, we started by looking at 2006
ethanol import data and made assumptions as to which countries would
likely contribute to the CBI ethanol volumes in Table V.B.3-1, and to
what extent.\138\ We estimated that, on average, in future years, 30%
would come from Jamaica, 20% each would come from El Salvador and Costa
Rica, and 15% each would originate from Trinidad & Tobago and the
Virgin Islands. Even though to date there have not been a lot of
ethanol imports from the Virgin Islands, we believe that they could
become a comparable importer to Trinidad & Tobago in the future under
the proposed RFS2 program.
---------------------------------------------------------------------------
\138\ Source: EIA data on company-level imports (http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historical.html).
---------------------------------------------------------------------------
From there, we looked at 2006-2007 import data and estimated the
general destination of Brazilian ethanol and the five contributing CBI
countries' domestic imports. Based on these countries' geographic
locations and import histories, we estimated that in 2022 about 75% of
the ethanol would be imported to the East and Gulf Coasts and the
remainder would go to the West Coast and Hawaii. To estimate import
locations, we considered coastal port cities that had received ethanol
or finished gasoline imports in 2006 and distributed the ethanol
accordingly based on ethanol demand. For more information on this
analysis, refer to Section 1.5 of the DRIA.
[[Page 24999]]
4. Biodiesel & Renewable Diesel
Biodiesel and renewable diesel are replacements for petroleum
diesel that are made from plant or animal fats. Biodiesel consists of
fatty acid methyl esters (FAME) and can be used in low-concentration
blends in most types of diesel engines and other combustion equipment
with no modifications. The term renewable diesel covers fuels made by
hydrotreating plant or animal fats in processes similar to those used
in refining petroleum. Renewable diesel is chemically analogous to
blendstocks already used in petroleum diesel, thus its use can be
transparent and its blend level essentially unlimited. The goal of both
biodiesel and renewable diesel conversion processes is to change the
properties of a variety of feedstocks to more closely match those of
petroleum diesel (such as its density, viscosity, and energy content)
for which the engines and distribution system have been designed. Both
processes can produce suitable fuels from biogenic sources, though we
believe some feedstocks lend themselves better to one process or the
other. The definition of biodiesel given in applicable regulations is
sufficiently broad to be inclusive of both fuels.\139\ However, the
EISA stipulates that renewable diesel that is co-processed with
petroleum diesel cannot be counted as ``biomass-based diesel'' for
purposes of complying with its volume mandates.\140\
---------------------------------------------------------------------------
\139\ See Section 1515 of the Energy Policy Act of 2005. More
discussion of the definitions of biodiesel and renewable diesel are
given in the preamble of the Renewable Fuel Standard rulemaking,
Section III.B.2, as published in the Federal Register Vol. 72, No.
83, p. 23917.
\140\ For more detailed discussion of the definition of
coprocessing and its implications for compliance with EISA, see
Section III.B.1 of this preamble.
---------------------------------------------------------------------------
In general, plant and animal oils are valuable commodities with
many uses other than transportation fuel. Therefore we expect the
primary limiting factor in the supply of both biodiesel and renewable
diesel to be feedstock availability and price. Expansion of their
market volumes is dependent on being able to compete on price with the
petroleum diesel they are displacing, which will depend largely on
continuation of current subsidies and other incentives.
Other biomass-based diesel fuel plants are either already built or
being considered for construction. Cello Energy has already started up
a 20 million gallon per year catalytic depolymerization plant that is
producing diesel fuel from cellulose and other feedstocks, and Cello
intends on building several 50 million gallon per year plants to be
started up in 2010. Also, numerous other companies are planning on
building biomass to liquids (BTL) plants that produce diesel fuel
through the syngas and Fischer Tropsch pathway. However, for our
analysis for this proposed rulemaking, we did not project that biomass-
based diesel fuel would be produced from these processes.
a. Historic and Projected Production
i. Biodiesel
As of September 2008, the aggregate production capacity of
biodiesel plants in the U.S. was estimated at 2.6 billion gallons per
year across approximately 176 facilities.\141\ Biodiesel plants exist
in nearly all states, with the largest density of plants in the Midwest
and Southeast where agricultural feedstocks are most plentiful.
---------------------------------------------------------------------------
\141\ Figures here were taken from National Biodiesel Board fact
sheet dated September 29, 2008 (http://biodiesel.org/pdf_files/fuelfactsheets/Producers%20Map%20-%20existing.pdf). This information
was current at the time these analyses were being done. More recent
data maintained by Biodiesel Magazine suggests that by April 2009
the industry had contracted to approximately 137 plants with
aggregate capacity of 2.3 billion gal/yr (see http://www.biodieselmagazine.com/plant-list.jsp).
---------------------------------------------------------------------------
Table V.B.4-1 gives U.S. biodiesel production capacity, sales, and
capacity utilization in recent years. The figures suggest that the
industry has grown out of proportion with actual biodiesel demand.
Reasons for this include various state incentives to build plants,
along with state and federal incentives to blend biodiesel, which have
given rise to an optimistic industry outlook over the past several
years. Since the cost of capital is relatively low for the biodiesel
production process (typically four to six percent of the total per-
gallon cost), this industry developed a more grassroots profile in
comparison to the ethanol industry, and, with median size less than 10
million gallons/yr, consists of a large number of small plants.\142\
These small plants, with relatively low operating costs other than
feedstock, have generally been able to survive producing below their
nameplate capacities.
---------------------------------------------------------------------------
\142\ Capital figures derived from USDA production cost models.
A publication describing USDA modeling of biodiesel production costs
can be found in Bioresource Technology 97(2006) 671-8.
\143\ Capacity data taken from National Biodiesel Board.
Production figures taken from F.O. Licht World Ethanol and Biofuels
Report, vol. 6, no. 11, p S271, except 2008, which is an estimate
taken from National Biodiesel Board (http://www.biodiesel.org/pdf_files/fuelfactsheets/Production_graph_slide.pdf).
Table V.B.4-1--U.S. Biodiesel Capacity and Production Volumes
[Million gallons] \143\
----------------------------------------------------------------------------------------------------------------
Utilization
Year Capacity Production (percent)
----------------------------------------------------------------------------------------------------------------
2003............................................................ 150 21 14%
2004............................................................ 245 36 15
2005............................................................ 395 115 29
2006............................................................ 792 241 30
2007............................................................ 1,809 499 28
2008............................................................ 2,610 700 27
----------------------------------------------------------------------------------------------------------------
Some of this industry capacity may not be dedicated specifically to
fuel production, instead being used to make oleochemical feedstocks for
further conversion into products such as surfactants, lubricants, and
soaps. These products do not show up in renewable fuel sales figures.
In 2004-5, demand for biodiesel grew rapidly, but the trend of
increasing capacity utilization was quickly overwhelmed by additional
plant starts. Since then, high commodity prices followed by reduced
demand for transportation fuel have caused additional economic strain
beyond the overcapacity situation. According to a survey conducted by
Biodiesel Magazine staff, more than 1 in 5 plants were already idle or
defunct as of late 2007 (though this likely varies by
[[Page 25000]]
region).\144\ A significant portion of the 2007 and 2008 production was
exported to Europe or Asia where fuel prices and additional tax
subsidies on top of those provided in the U.S. help cover
transportation overseas and offset high feedstock costs. The Energy
Information Administration is beginning to collect data on biodiesel
imports and exports, but reports are not expected until later in 2009.
Therefore precise figures are not available on what fraction of
production was consumed domestically, but sources familiar with the
industry suggest exports may have been as much as 200 million gallons
in 2007 and likely more in 2008.\145\ We do not account for any
biodiesel exports in our analysis, though there will be sufficient
plant capacity to produce material beyond the volumes required in the
EISA should an export market exist.
---------------------------------------------------------------------------
\144\ Derived from figures published in Biodiesel Magazine, May
2008, p. 39.
\145\ Staff-level communication with National Biodiesel Board
(April 2008).
---------------------------------------------------------------------------
To perform our distribution and emission impacts analyses for this
proposal, it was necessary to forecast the state of the biodiesel
industry in the timeframe of the fully-phased-in RFS. In general, this
consisted of reducing the over-capacity to be much closer to the amount
demanded, which we assumed to be equal to the requirement under the
EISA given uncertainties about feedstock prices and changes in tax
incentives in the long term. This was accomplished by considering as
screening factors the current production and sales incentives in each
state as well as each plant's primary feedstock type and whether it was
BQ-9000 certified.\146\ Going forward producers will compete for
feedstocks and markets will consolidate. During this period the number
of operating plants is expected to shrink, with surviving plants adding
feedstock segregation and pre-treatment capabilities, giving them
flexibility to process any mix of feedstocks available in their area.
By the end of this period we project a mix of large regional plants and
some smaller plants taking advantage of local market niches, with an
overall average capacity utilization around 80% for dedicated fuel
plants. Table V.B.4-2 summarizes this forecast. See Section 1.5.4 of
the DRIA for more details.
---------------------------------------------------------------------------
\146\ Information on state incentives was taken from U.S.
Department of Energy Web site, accessed July 30, 2008, at http://www.eere.energy.gov/afdc/fuels/biodiesel_laws.html. Information on
feedstock and BQ-9000 status was taken from Biodiesel Board fact
sheet, accessed July 30, 2008, at http://biodiesel.org/pdf_files/fuelfactsheets/Producers%20Map%20-%20existing.pdf.
Table V.B.4-2--Summary of Projected Biodiesel Industry Characterization
Used in Our Analyses \147\
------------------------------------------------------------------------
2008 2022
------------------------------------------------------------------------
Total production capacity on-line (million gal/yr).... 2,610 1,050
Number of operating plants............................ 176 35
Median plant size (million gal/yr).................... 5 30
Total biodiesel production (million gal).............. 700 810
Average plant utilization............................. 0.27 0.77
------------------------------------------------------------------------
ii. Renewable Diesel
Renewable diesel is a fuel (or blendstock) produced from animal
fats, vegetable oils, and waste greases using chemical processes
similar to those employed in petroleum hydrotreating. These processes
remove oxygen and saturate olefins, converting the triglycerides and
fatty acids into paraffins. Renewable diesel typically has higher
cetane, lower nitrogen, and lower aromatics than petroleum diesel fuel,
while also meeting stringent sulfur standards.
---------------------------------------------------------------------------
\147\ Industry data for 2008 taken from National Biodiesel Board
fact sheets at http://www.biodiesel.org/buyingbiodiesel/producers_marketers/Producers%20Map-Existing.pdf and http://www.biodiesel.org/pdf_files/fuelfactsheets/Production_graph_slide.pdf (both
accessed April 27, 2009).
---------------------------------------------------------------------------
In comparison to biodiesel, renewable diesel has improved storage,
stability, and shipping properties as a result of the oxygen and
olefins in the feedstock being removed. This allows renewable diesel
fuel to be shipped in existing petroleum pipelines used for
transporting fuels, thus avoiding one significant issue with
distribution of biodiesel. For more on fuel distribution, refer to
Section V.C.
Considering that this industry is still in development and that
there are no long-term projections of production volume, we base our
production estimates primarily on the potential volume of feedstocks
for this process, in the context of recent industry project
announcements involving proven technology. We project that
approximately two-thirds of renewable diesel will be produced at
existing petroleum refineries, and half will be co-processed with
petroleum (thus prohibiting it from counting as ``biomass-based
diesel'' under the EISA). Tables V.B.4-3 and V.B.4-4 summarize these
volumes.
Table V.B.4-3--Projected Renewable Diesel Volumes by Production Category
[Million gallons in 2022]
------------------------------------------------------------------------
Existing New
facility facility
------------------------------------------------------------------------
Co-processed with petroleum................... 188 --
Not co-processed with petroleum............... 63 125
------------------------------------------------------------------------
b. Feedstock Availability
The primary feedstock for domestic biodiesel production has
historically been soybean oil, with other plant and animal fats as well
as recycled greases making up a smaller but significant portion of the
biodiesel pool. Agricultural commodity modeling we have done for this
proposal (see Section IX.A) suggests that soybean oil production will
stay relatively flat in the future, causing supplies to tighten and
prices to rise as demand increases for biofuels and food uses
worldwide. The output of these models suggests that domestic soy oil
production could support about 550 million gallons per year in 2022.
This material is most likely to be processed by biodiesel plants due to
the large available capacity of these facilities and their proximity to
soybean production. Compared to other feedstocks, virgin plant oils are
more easily processed into biofuel via simple transesterification due
to their homogeneity of composition and lack of contaminants.
Another source of feedstock which could provide increasing and
significant volume is oil extracted from corn or its co-products in the
dry mill ethanol production process. Sometimes referred to as corn
fractionation or dry separation, these processes get additional
products of value from the dry milling process. This idea is not
[[Page 25001]]
new, as existing wet mill plants create several product streams from
their corn input, including oil. Corn fractionation can be seen as a
way to get some of this added value without incurring the larger
capital costs and potentially lower ethanol yields associated with wet
mill plants. More detailed discussion of these processes and how they
affect the co-product stream(s) can be found in DRIA Section 1.4.1.3.
The corn oil process on which we have chosen to focus for cost and
volume estimates in this proposal is one that extracts oil from the
thin stillage after fermentation (the non-ethanol liquid material that
typically becomes part of distillers' grains with solubles). We believe
installation of this type of equipment will be attractive to industry
because it can be added onto an existing dry mill plant and does not
impact ethanol yields since it does not process the corn prior to
fermentation. Depending on the configuration, such a system can extract
20-50% of the oil from the co-product streams, and produces a
distressed corn oil (non-food-grade, with some free fatty acids and/or
oxidation by-products) product stream which can be used as feedstock by
biodiesel facilities. Since it offers another stream of revenue, we
believe it is reasonable to expect about 40% of projected total ethanol
production to implement some type of oil extraction process by 2022,
generating approximately 150 million gallons per year of corn oil
biofuel feedstock.\148\ We expect this material to be processed in
biodiesel plants.
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\148\ See Table 3 in Mueller, Steffen. An analysis of the
projected energy use of future dry mill corn ethanol plants (2010-
2030). October 10, 2007. Available at http://www.chpcentermw.org/pdfs/2007CornEthanolEnergySys.pdf.
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Rendered animal fats and reclaimed cooking oils and greases are
another potentially significant source of biodiesel feedstock. We
estimate that just two to four percent of biodiesel in 2007 was
produced from waste cooking oils and greases, though this number is
likely higher more recently.\149\ Tyson Foods, in joint efforts with
ConocoPhilips and Syntroleum, announced construction plans in 2008 for
renewable diesel production facilities to begin operating in 2010 and
producing up to 175 million gallons annually (combined capacity). By
the end of our projection period, as much as 30% of rendered fats and
waste grease could be converted to biofuel while still supporting
production of pet food, soaps and detergents, and other
oleochemicals.\150\ We request comment from members of these industries
on any potential impacts of diversion of rendered materials to biofuel.
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\149\ Based on plant capacities reported by the National
Biodiesel Board and data reported by F.O. Licht.
\150\ Based on statements from the National Renderer's
Association.
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Under this assumption, this material could make approximately 500
million gallons of biofuel (though we have not chosen to allocate all
of it in our analyses here). We estimate this type of material could be
most economically made into renewable diesel in the long term, as that
process does not have the same sensitivities to free fatty acids and
other contaminates typically present in waste greases as the biodiesel
process; however, some amount of this material may continue to be
processed in biodiesel plants that have acid pretreatment capabilities
where it makes economic sense. Recent market shifts and changes in tax
subsidies enacted after analyses were done for this NPRM have affected
the relative economics of using waste fats and greases for biodiesel
versus renewable diesel. We will reevaluate our assumptions in the FRM.
Our analysis of the countries with the most potential to produce
and consume biodiesel in the future suggests that supplies of finished
biodiesel will be tight, and prices of its feedstocks will remain high.
Supplies to the U.S. will be limited by biofuel mandates and targets of
other countries, preferential shipment of biodiesel to European and
Asian nations, and the speed at which non-traditional crops such as
jatropha can be developed. Thus, we cannot at this time project more
than negligible amounts of biodiesel or its feedstocks being available
for import into the U.S. in the future. For more discussion of
international movement of biodiesel and its feedstocks, refer to
Section 1.1 of the DRIA.
Table V.B.4-4 shows the projected potential contribution of these
sources we have chosen to quantify. Other potential, but less certain,
sources for biodiesel feedstocks include conversion of some existing
croplands used for soybeans to higher-yielding oilseed crops.
Production of oil from algae farms is also being investigated by a
number of companies and universities as a source of biofuel feedstock.
For additional discussion of such sources, refer to Section 1.1 of the
DRIA.
Table V.B.4-4--Estimated Potential Biodiesel and Renewable Diesel
Volumes in 2022
[Million gallons of fuel]
------------------------------------------------------------------------
Biomass-based diesel Other
-------------------------- advanced
biofuel
Renewable ------------
Biodiesel diesel Renewable
diesel
------------------------------------------------------------------------
Virgin plant oils................ 660 -- --
Corn fractionation............... 150 -- --
Rendered fats and greases........ -- 188 188
------------------------------------------------------------------------
C. Renewable Fuel Distribution
The following discussion pertains to the distribution of biofuels.
A discussion of the distribution of biofuel feedstocks and co-products
is contained in Section 1.3.3 and 5.1 of the DRIA respectively. In
conducting our analysis of biofuel distribution, we took into account
the projected size and location of biofuel production facilities and
where we project biofuels would be used.\151\
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\151\ The location of biofuel production facilities and where
biofuels would be used is discussed in Sections 1.5 and 1.7 of the
DRIA respectively and earlier in this Section V of the preamble.
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The current motor fuel distribution infrastructure has been
optimized to facilitate the movement of petroleum-based fuels.
Consequently, there are very efficient pipeline-terminal networks that
move large volumes of petroleum-based fuels from production/import
centers on the Gulf Coast and the Northeast into the heartland of the
[[Page 25002]]
country. In contrast, the majority of renewable fuel is expected to be
produced in the heartland of the country and will need to be shipped to
the coasts, flowing roughly in the opposite direction of petroleum-
based fuels. This limits the ability of renewable fuels to utilize the
existing fuel distribution infrastructure.
The modes of distributing renewable fuels to the end user vary
depending on constraints arising from their physical/chemical nature
and their point of origination. Some fuels are compatible with the
existing fuel distribution system, while others currently require
segregation from other fuels. The location of renewable fuel production
plants is also often dictated by the need to be close to the source of
the feedstocks used rather than to fuel demand centers or to take
advantage of the existing petroleum product distribution system. Hence,
the distribution of renewable fuels raises unique concerns and in many
instances requires the addition of new transportation, storage,
blending, and retail equipment.
Significant challenges must be faced in reconfiguring the
distribution system to accommodate the large volumes of ethanol and to
a lesser extent biodiesel that we project will be used. While some
uncertainties remain, particularly with respect to the ability of the
market to support the use of the volume of E85 needed, no technical
barriers appear to be insurmountable. The response of the
transportation system to date to the unprecedented increase in ethanol
use is encouraging. A U.S. Department of Agriculture (USDA) report
concluded that logistical concerns have not hampered the growth in
ethanol production, but that concerns may arise about the adequacy of
transportation infrastructure as the growth in ethanol production
continues.\152\
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\152\ ``Ethanol Transportation Backgrounder, Expansion of U.S.
Corn-based Ethanol from the Agricultural Transportation
Perspective'', USDA, September 2007, http://www.ams.usda.gov/tmd/TSB/EthanolTransportationBackgrounder09-17-07.pdf.
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Considerable efforts are underway by individual companies in the
fuel distribution system, consortiums of such companies, industry
associations, independent study groups, and inter-agency governmental
organizations to evaluate what steps may be necessary to facilitate the
necessary upgrades to the distribution system to support compliance
with the RFS2 standards.\153\ EPA will continue to participate/monitor
these efforts as appropriate to keep abreast of potential problems in
the biofuel distribution system which might interfere with the use of
the volumes of biofuels that we project will be needed to comply with
the RFS2 standards. The 2008 Farm Act (Title IX) requires USDA, DOE,
DOT, and EPA to conduct a biofuels infrastructure study that will
assess infrastructure needs, analyze alternative development
approaches, and provide recommendations for specific infrastructure
development actions to be taken.\154\
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\153\ For example: (1) The Biomass Research and Development
Board, a government study group, has formed a task group on biofuels
distribution infrastructure that is composed of experts on biofuel
distribution from a broad range of governmental agencies. (2) The
National Commission on Energy Policy, an independent advisory group,
has formed a task group of fuel distribution experts to make
recommendations on the steps needed to facilitate the distribution
of biofuels. (3) The Association of Oil Pipelines is conducting
research to evaluate what steps are necessary to allow the
distribution of ethanol blends by pipeline.
\154\ http://www.ers.usda.gov/FarmBill/2008/Titles/TitleIXEnergy.htm#infrastructure.
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Considerations related to the distribution of ethanol, biodiesel,
and renewable diesel are discussed in the following sections as well as
the changes to each segment in the distribution system that would be
needed to support the volumes of these biofuels that we project would
be used to satisfy the RFS2 standards.\155\ We request comments on the
challenges that will be faced by the fuel distribution system under the
RFS2 standards and on what steps will be necessary to facilitate making
the necessary accommodations in a timely fashion.\156\
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\155\ Additional discussion can be found in Section 1.6 of the
DRIA.
\156\ The costs associated with making the necessary changes to
the fuel distribution infrastructure are discussed in Section VIII.B
of today's preamble.
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To the extent that biofuels other than ethanol and biodiesel are
produced in response to the RFS2 standards, this might lessen the need
for added segregation during distribution. Distillate fuel produced
from cellulosic feedstocks might be treated as petroleum-based diesel
fuel blendstocks or a finished distillate fuel in the distribution
system. Likewise, bio-gasoline or bio-butanol could potentially be
treated as petroleum-based gasoline blendstocks.\157\ This also might
open the possibility for additional transport by pipeline. However, the
location of plants that produce such biofuels relative to petroleum
pipeline origination points would continue to be an issue limiting the
usefulness of existing pipelines for biofuel distribution.\158\
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\157\ Biogasoline might also potentially be treated as finished
fuel.
\158\ The projected location of biofuel plants would not be
affected by the choice of whether they are designed to produce
ethanol, distillate fuel, bio-gasoline, or butanol. Proximity to the
feedstock would continue to be the predominate consideration. The
use of pipelines is being considered for the shipment of bio-oils
manufactured from cellulosic feedstocks to refineries where they
could be converted into renewable diesel fuel or renewable gasoline.
The distribution of biofuel feedstocks is discussed in Section 1.3
of the DRIA.
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1. Overview of Ethanol Distribution
Pipelines are the preferred method of shipping large volumes of
petroleum products over long distances because of the relative low cost
and reliability. Ethanol is currently not commonly shipped by pipeline
because it can cause stress corrosion cracking in pipeline walls and
its affinity for water and solvency can result in product contamination
concerns.\159\ Shipping ethanol in pipelines that carry distillate
fuels as well as gasoline also presents unique difficulties in coping
with the volumes of a distillate-ethanol mixture which would typically
result.\160\ It is not possible to re-process this mixture in the way
that diesel-gasoline mixtures resulting from pipeline shipment are
currently handled.\161\ Substantial testing and analysis is currently
underway to resolve these concerns so that ethanol may be shipped by
pipeline either in a batch mode or blended with petroleum-based
fuel.\162\ By the time of the publication of this proposal, results of
these evaluations may be available regarding what actions are necessary
by multi-product pipelines to overcome safety and product contamination
concerns associated with shipping 10% ethanol blends. A short gasoline
pipeline in Florida has begun shipping
[[Page 25003]]
batches of ethanol.\163\ Thus, existing petroleum pipelines in some
areas of the country might play a role in the shipment of ethanol from
the points of production/importation to petroleum terminals.
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\159\ Stress corrosion cracking could lead to a pipeline leak.
The potential impacts on water from today's proposal are discussed
in Section X of today's preamble.
\160\ Different grades of gasoline and diesel fuel are typically
shipped in multi-product pipelines in batches that abut each other.
To the extent possible, products are sequenced in a way to allow the
interface mixture between batches to be cut into one of the
adjoining products. In cases where diesel fuel abuts gasoline in the
pipeline, the resulting mixture must typically be reprocessed into
its component parts by distillation for resale as gasoline and
diesel fuel.
\161\ Gasoline-ethanol mixtures can be blended into finished
gasoline.
\162\ Association of Oil Pipelines: http://aopl.org/go/searchresults/888/?q=ethanol&sd=&ed=. ``Hazardous Liquid Pipelines
Transporting Ethanol, Ethanol Blends, and Other Biofuels'', Notice
of policy statement and request for comment, Pipeline and Hazardous
Materials Safety Administration, Department of Transportation,
August 10, 2007, 72 FR 45002.
\163\ Article on shipment of ethanol in Kinder Morgan pipeline:
http://www.ethanolproducer.com/article.jsp?article_id=5149.
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However, the location of ethanol plants in relation to existing
pipeline origination points will limit the role of existing pipelines
in the shipment of ethanol.\164\ Current corn ethanol production
facilities are primarily located in the Midwest far from the
origination points of most existing product pipelines and the primary
gasoline demand centers. We project that a substantial fraction of
future cellulosic ethanol plants will also be located in the Midwest,
although a greater proportion of cellulosic plants are expected to be
dispersed throughout the country compared to corn ethanol plants. The
projected locations for this subset of future cellulosic ethanol plants
more closely coincide with the origination points of product pipelines
in the Gulf Coast.\165\ Imported ethanol could also be brought into
ports near the origination point of product pipelines in the Gulf Coast
and the Northeast. Nevertheless, the majority of ethanol will continue
to be produced at locations distant from the origination points of
product pipelines and gasoline demand centers. The gathering of ethanol
from production facilities located in the Midwest and shipment by barge
down the Mississippi for introduction to pipelines in the Gulf Coast is
under consideration. However, the additional handling steps to bring
the ethanol to the pipeline origin points in this manner could negate
any potential benefit of shipment by existing petroleum pipelines
compared to direct shipment by rail.
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\164\ Some small petroleum product refineries are currently
limited in their ability to ship products by pipeline because their
relatively low volumes were not sufficient to justify connection to
the pipeline distribution system.
\165\ A discussion of the projected location of cellulosic
ethanol plants is contained in Section 1.5 of the DRIA.
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Evaluations are also currently underway regarding the feasibility
of constructing a new dedicated ethanol pipeline from the Midwest to
the East Coast.\166\ Under such an approach, ethanol would be gathered
from a number of Midwest production facilities to provide sufficient
volume to justify pipeline operation. To the extent that ethanol
production would be further concentrated in the Midwest due to the
siting of cellulosic ethanol plants, this would tend to help justify
the cost of installing a dedicated ethanol pipeline. Substantial issues
would need to be addressed before construction on such a pipeline could
proceed, including those associated with securing new rights-of-ways
and establishing sufficient surety regarding the return on the several
billion dollar investment.
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\166\ Magellan and Poet joint assessment of dedicated ethanol
pipeline: http://www.magellanlp.com/news/2009/20090316_5.htm.
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Due to the uncertainties regarding the degree to which pipelines
will be able to participate in the transportation of ethanol, we
assumed that ethanol will continue to be transported by rail, barge,
and truck to the terminal where it will be blended into gasoline. The
distribution by these modes can be further optimized primarily through
the increased shipment by unit train and installation of additional hub
delivery terminals that can accept large volumes of ethanol for further
distribution to satellite terminals. To the extent that pipelines do
eventually play a role in the distribution of ethanol, this could tend
to reduce distribution costs and improve reliability in supply.
USDA estimated that in 2005 approximately 60% of ethanol was
transported by rail, 30% was transported by tank truck, and 10% was
transported by barge.\167\ Denatured ethanol is shipped from
production/import facilities to petroleum terminals where it is blended
with gasoline. When practicable, shipment by unit train is the
preferred method of rail shipment rather than shipping on a manifest
rail car basis. The use of unit trains, sometimes referred to as a
virtual pipeline, substantially reduces shipping costs and improves
reliability. Unit trains are composed entirely of 70-100 ethanol tank
cars, and are dedicated to shuttle back and forth to large hub
terminals.\168\ Manifest rail car shipment refers to the shipment of
ethanol in rail tank cars that are incorporated into trains which are
composed of a variety of other commodities. Unit trains can be
assembled at a single ethanol production plant or if a group of plants
is not large enough to support such service individually, can be formed
at a central facility which gathers ethanol from a number of producers.
The Manly Terminal in Iowa, which is the first such ethanol gathering
facility, accepts ethanol from a number of nearby ethanol production
facilities for shipment by unit train. Regional (Class 2) railroad
companies are an important link bringing ethanol to gathering
facilities for assembly into unit trains for long-distance shipment by
larger (Class 1) railroads. Ethanol is sometimes carried by multiple
modes before finally arriving at the terminal where it is blended into
gasoline. For example, some ethanol is currently shipped from the
Midwest to a hub terminal on the East Coast by unit train where a
portion is further shipped to satellite terminals by barge or tank
truck.
---------------------------------------------------------------------------
\167\ ``Ethanol Transportation Backgrounder, Expansion of U.S.
Corn-based Ethanol from the Agricultural Transportation
Perspective'', USDA, September 2007, http://www.ams.usda.gov/tmd/TSB/EthanolTransportationBackgrounder09-17-07.pdf.
\168\ Hub ethanol receipt terminals can be located at large
petroleum terminals or at rail terminals.
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Ethanol is blended into gasoline at either 10 or 85 volume percent
at terminals (to produce E10 and E85) for delivery to retail and fleet
facilities by tank truck. Special retail delivery hardware is needed
for E85 which can be used in flexible fuel vehicles only.\169\ The
large volume of ethanol that we project will be used by 2022 means that
more ethanol will need to be used than can be accommodated by blending
to the current legal limit of 10% in all of the gasoline used in the
country. This will require the installation of a substantial number of
new E85 refueling facilities and the addition of a substantial number
of flex-fuel vehicles to the fleet. Concerns have been raised regarding
the inducements that would be necessary for retailers to install the
needed E85 facilities and for consumers to purchase E85.\170\ As
discussed in Section V.D. of today's preamble, this is prompting many
to evaluate whether a mid-level ethanol blend (e.g. E15) might be
allowed for use in existing (non-flex-fuel) vehicles. Current refueling
equipment (not designed for E85) is only certified for ethanol blends
up to 10 volume percent (E10).\171\ Hence, if a mid-level ethanol blend
were to be introduced, fuel retail facilities would need to ensure that
the equipment used to store/dispense mid-level ethanol
[[Page 25004]]
blends is compatible with the mid-level ethanol blend.\172\
Underwriters Laboratories has one certification standard for fuel
retail equipment that covers ethanol blends up to 10%, and a separate
certification standard for equipment that dispenses ethanol blends
above 10% (including E85).\173\
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\169\ The cost of retail dispensing hardware which is tolerant
to ethanol blends greater than E10 is discussed in Section VIII.B.
of today's preamble and discussed in more detail in Section 4.2 of
the DRIA.
\170\ See Section V.D of today's preamble for a discussion of
issues related to use of the projected volumes of ethanol that would
be produced to comply with the RFS2 standards.
\171\ Underwriters Laboratory certifies retail refueling
equipment. UL stated that they have data which indicates that the
use of fuel dispensers certified for up to E10 blends to dispense
blends up to a maximum ethanol content of 15 volume percent would
not result in critical safety concerns (http://www.ul.com/newsroom/newsrel/nr021909.html). Based on this, UL stated that it would
support authorities having jurisdiction who decide to permit legacy
equipment originally certified for up to E10 blends to be used to
dispense up to 15 volume percent ethanol. The UL announcement did
address the compatibility of underground storage tank systems with
greater than E10 blends.
\172\ Although it has yet to be established, most underground
steel storage tanks themselves would likely be compatible with
ethanol blends greater than 10 percent. The compatibility of piping,
submersed pumps, gaskets, and seals associated with these tanks with
ethanol blends greater than 10% would also need to be evaluated.
Some fiberglass tanks are incompatible and would need to be
replaced. It is difficult and sometimes impossible to verify the
suitability of underground storage tanks and tank-related equipment
for E85 use. The State of California prohibits the conversion of
underground storage tanks to E85 use. Significant changes to
dispensers, including hoses, nozzles, and other miscellaneous
fittings would be needed to ensure they are compatible with ethanol
blends greater than 10 percent.
\173\ Joint UL/DOE Legacy System Certification Clarification
http://www.ul.com/global/eng/documents/offerings/industries/chemicals/flammableandcombustiblefluids/development/UL_DOE_LegacySystemCertification.pdf.
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Should other biofuels be introduced that do not require
differentiation from diesel fuel or gasoline in place of some of the
volume of ethanol that we project would be used under the RFS2
standards, this may tend to reduce the need for changes at fuel retail
facilities and the need for flex-fuel vehicles. Concerns about the
difficulties/costs associated with expanding the ethanol distribution
infrastructure and adding a sufficient number of vehicles capable of
using 10% ethanol to fleet is generating increased industry interest in
renewable diesel and gasoline which would be more transparent to the
existing fuel distribution system.
2. Overview of Biodiesel Distribution
Biodiesel is currently transported from production plants by truck,
manifest rail car, and by barge to petroleum terminals where it is
blended with petroleum-based diesel fuel. Unblended biodiesel must be
transported and stored in insulated/heated containers in colder climes
to prevent gelling. Insulated/heated containers are not needed for
biodiesel that has been blended with petroleum-based diesel fuel (i.e.,
B2, B5). Biodiesel plants are not as dependent on being located close
to feedstock sources as are corn and cellulosic ethanol plants.\174\
Biodiesel feedstocks are typically preprocessed to oil prior to
shipment to biodiesel production facilities. This can substantially
reduce the volume of feedstocks shipped to biodiesel plants relative to
ethanol plants, and has allowed some biodiesel plants to be located
adjacent to petroleum terminals. Biodiesel production facilities are
more geographically dispersed than ethanol facilities and the
production volumes also tend to be smaller than ethanol
facilities.\175\ These characteristics in combination with the smaller
volumes of biodiesel that we project will be used under the RFS2
standards compared to ethanol allow relatively more biodiesel to be
used within trucking distance of the production facility. However, we
project that there will continue to be a strong and growing demand for
biodiesel as a blending component in heating oil which could not be
satisfied alone by local sources of production. It is likely that state
biodiesel mandates will also need to be satisfied in part by out-of-
state production. Fleets are also likely to continue to be a
substantial biodiesel user, and these will not always be located close
to biodiesel producers. Thus, we are assuming that a substantial
fraction of biodiesel will continue to be shipped long distances to
market. Downstream of the petroleum terminal, B2 and B5 can be
distributed in the same manner as petroleum diesel.
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\174\ Biodiesel feedstocks are typically preprocessed to oil
prior to shipment to biodiesel production facilities. This can
substantially reduce the volume of feedstocks shipped to biodiesel
plants relative to ethanol plants.
\175\ Section 1.2 contains a discussion of our projections
regarding the location of biodiesel production facilities.
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Concerns remain regarding the shipment of biodiesel by pipeline
(either by batch mode or in blends with diesel fuel) related to the
contamination of other products (particularly jet fuel), the solvency
of biodiesel, and compatibility with pipeline gaskets and seals.\176\
The smaller anticipated volumes of biodiesel and the more dispersed and
smaller production facilities relative to ethanol also make biodiesel a
less attractive candidate for shipment by pipeline. Due to the
uncertainties regarding the suitability of transporting biodiesel by
pipeline, we assumed that biodiesel which needs to be transported over
long distance will be carried by manifest rail car and to a lesser
extent barge. Due to the relatively small plant size and dispersion of
biodiesel plants, we anticipate the volumes of biodiesel that can be
gathered at a single location will continue to be insufficient to
justify shipment by unit train. To the extent that pipelines do
eventually play a role in the distribution of biodiesel, this could
tend to reduce distribution costs and improve reliability in supply.
---------------------------------------------------------------------------
\176\ Industry evaluations are currently underway to resolve
these concerns.
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3. Overview of Renewable Diesel Distribution
We believe that renewable diesel fuel will be confirmed to be
sufficiently similar to petroleum-based diesel fuel blendstocks with
respect to distribution system compatibility. Hence, renewable diesel
fuel could be treated in the same manner as any petroleum-based diesel
fuel blendstock with respect to transport in the existing petroleum
distribution system. Approximately two-thirds of renewable diesel fuel
is projected to be produced at petroleum refineries.\177\ The transport
of such renewable diesel fuel would not differ from petroleum-based
diesel fuel since it would be blended to produce a finished diesel fuel
before leaving the refinery. The other one-third of renewable diesel
fuel is projected to be produced at stand-alone facilities located more
closely to sources of feedstocks. We anticipate that such renewable
diesel fuel would be shipped by tank truck to nearby petroleum
terminals where it would be blended directly into diesel fuel storage
tanks. Because of its high cetane and value, we anticipate that all
renewable diesel fuel would likely be blended with petroleum based
diesel fuel prior to use. Downstream of the terminal, renewable/
petroleum diesel fuel mixtures would be distributed the same as
petroleum diesel.
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\177\ Either co-processed with crude oil or processed in
separate units at the refinery for blending with other refinery
diesel blendstocks.
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4. Changes in Freight Tonnage Movements
To evaluate the magnitude of the challenge to the distribution
system up to the point of receipt at the terminal, we compared the
growth in freight tonnage for all commodities from the AEO 2007
reference case to the growth in freight tonnage under the RFS2
standards in which ethanol increases, as does the feedstock (corn) and
co-products (distillers grains). We did not include a consideration of
the distribution of cellulosic ethanol feedstocks on freight tonnage
for the proposal. We intend to evaluate this in the final rule. For
purposes of this analysis, we focused on only the ethanol portion of
the renewable fuel goals for ease of calculation and because ethanol
represents the vast majority of the total volume of biofuel. The
resulting calculations serve as an indicator of changes in freight
tonnages associated with increases in renewable fuels. We calculated
the freight tonnage for the total of all modes of transport as well as
the individual cases of rail, truck, and barge.
[[Page 25005]]
In calculating the reference case percent growth rate in total
freight tonnage, we used data compiled by the Federal Highway
Administration to calculate the tonnages associated with these
commodities.\178\ We then calculated the growth in freight tonnage for
2022 under the RFS2 standards and compared the difference with the
reference case. The comparisons indicate that across all transport
modes, the incremental increase in freight tonnage of ethanol and
accompanying feedstocks and co-products associated with the increased
ethanol volume under the RFS2 standards are small. The percent increase
for total freight across all modes (including pipeline) by 2022 is 0.9
percent. Because pipelines currently do not carry ethanol, and the
increase in the volume of ethanol used in motor vehicles displaces a
corresponding volume of gasoline, pipelines showed a decrease in the
total tonnage carried due to a decrease in the volume of gasoline
carried by pipeline. The displaced gasoline also resulted in some
decrease in tonnage in other modes that slightly reduced the overall
increases in tonnage reflected in the totals.
---------------------------------------------------------------------------
\178\ http://www.ops.fhwa.dot.gov/freight/freight_analysis/faf/index.htm.
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To further evaluate the magnitude of the increase in freight
tonnage under the RFS2 standards, we calculated the portion of the
total freight tonnage for rail, barge, and truck modes made up of
ethanol-related freight for both the 2022 and control cases. The
freight associated with ethanol constitutes only a very small portion
of the total freight tonnage for all commodities. Specifically, ethanol
freight represents approximately 0.5% and 2.5% of total freight for the
reference case and RFS2 standards case, respectively. The results of
this analysis suggest that it should be feasible for the distribution
infrastructure upstream of the terminal to accommodate the additional
freight associated with this RFS2 standards especially given the lead
time available. Specific issues related to transportation by rail,
barge, and tank truck are discussed in the following sections. We
intend to incorporate the results of a recently completed study by Oak
Ridge National Laboratory (ORNL) on the potential constraints in
ethanol distribution into the analysis for the final rule.\179\ The
ORNL study concluded that the increase in ethanol transport would have
minimal impacts on the overall transportation system. However, the ORNL
study did identify localized areas where significant upgrades to the
rail distribution system would likely be needed.
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\179\ ``Analysis of Fuel Ethanol Transportation Activity and
Potential Distribution Constraints'', prepared for EPA by Oak Ridge
National Laboratory, March 2009.
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5. Necessary Rail System Accommodations
Many improvements to the freight rail system will be required in
the next 15 years to keep pace with the large increase in the overall
freight demand. Improvements to the freight railroad infrastructure
will be driven largely by competition in the burgeoning inter-model
transport sector. As inter-model freight represents the vast majority
of all freight hauled by these railroads, the biofuels transport sector
can be expected to benefit from the infrastructure build-out resulting
from inter-model transport sector competition. As such, most of the
needed upgrades to the rail freight system are not specific to the
transport of renewable fuels and would be needed irrespective of
today's proposed rule. We also expect that the excess rail capacity
associated with inter-model build-out to be adequately large to absorb
potential increases in truck transport associated with fuel cost
increases. The modifications required to satisfy the increase in demand
include upgrading tracks to allow the use of heavier trains at faster
speeds, the modernization of train braking systems to allow for
increased traffic on rail lines, the installation of rail sidings to
facilitate train staging and passage through bottlenecks.
Some industry groups \180\ and governmental agencies in discussions
with EPA, and in testimony provided for the Surface Transportation
Board (STB) expressed concerns about the ability of the rail system to
keep pace with the large increase in demand even under the reference
case (27% by 2022). For example, the electric power industry has had
difficulty keeping sufficient stores of coal in inventory at power
plants due to rail transport difficulties and has expressed concerns
that this situation will be exacerbated if rail congestion worsens. One
of the more sensitive bottleneck areas with respect to the movement of
ethanol from the Midwest to the East coast is Chicago. The City of
Chicago commissioned its own analysis of rail capacity and congestion,
which found that the lack of rail capacity is ``no longer limited to a
few choke points, hubs, and heavily utilized corridors.'' Instead, the
report finds, the lack of rail capacity is ``nationwide, affecting
almost all the nation's critically important trade gateways, rail hubs,
and intercity freight corridors.''
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\180\ Industry groups include the Alliance of Automobile
Manufacturers, American Chemistry Council, and the National
Industrial Transportation League; governmental agencies include the
Federal Railroad Administration (FRA), the Government Accountability
Office (GAO), and the American Association of State Highway
Transportation Officials (AASHTO). Testimony for the STB public
hearings includes Ex Parte No. 671, Rail Capacity and Infrastructure
Requirements and Ex Parte No. 672, Rail Transportation and Resources
Critical to the Nation's Energy Supply.
---------------------------------------------------------------------------
Significant private and public resources are focused on making the
modifications to the rail system to cope with the increase in demand.
Rail carriers report that they typically invest $16 to $18 billion a
year in infrastructure improvements.\181\ Substantial government loans
are also available to small rail companies to help make needed
improvements by way of the Railroad Rehabilitation and Improvement
Finance (RRIF) Program, administered by Federal Railroad Administration
(FRA), as well as Section 45G Railroad Track Maintenance Credits,
offered by the Internal Revenue Service (IRS). The American Association
of State Highway Transportation Officials (AASHTO) estimates that
between $175 billion and $195 billion must be invested over a 20-year
period to upgrade the rail system to handle the anticipated growth in
freight demand, according to the report's base-case scenario.\182\ The
report suggests that railroads should be able to provide up to $142
billion from revenue and borrowing, but that the remainder would have
to come from other sources including, but not limited, to loans, tax
credits, sale of assets, and other forms of public-sector
participation. Given the reported historical investment in rail
infrastructure, it may be reasonable to assume that rail carriers would
be able to manage the $7.1 billion in annual investment from rail
carriers that AASHTO projects would be needed to keep pace with the
projected increase in freight demand.
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\181\ ``The Importance of Adequate Rail Investment'',
Association of American Railroads, http://www.aar.org/GetFile.asp?File_ID=150.
\182\ AASHTO Freight-Rail Bottom-Line Report, 2003.
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However, the Government Accounting Office (GAO) found that it is
not possible to independently confirm statements made by Class I rail
carriers regarding future investment plans.\183\ In
[[Page 25006]]
addition, questions persist regarding allocation of these investments,
with the Alliance of Automobile Manufacturers, American Chemistry
Council, National Industrial Transportation League, and others
expressing concern that their infrastructural needs may be neglected by
the Class I railroads in favor of more lucrative intermodal traffic.
Moreover, the GAO has raised questions regarding the competitive nature
and extent of Class I freight rail transport. This raises some concern
that providing sufficient resources to facilitate the transport of
increasing volumes of ethanol and biodiesel might not be a first
priority for rail carriers. In response to GAO concerns, the Surface
Transportation Board (STB) agreed to undertake a rigorous analysis of
competition in the freight railroad industry.\184\
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\183\ The railroads interviewed by GAO were generally unwilling
to discuss their future investment plans with the GAO. Therefore,
GAO was unable to comment on how Class I freight rail companies are
likely to choose among their competing investment priorities for the
future, including those of the rail infrastructure, GAO testimony
Before the Subcommittee on Surface Transportation and Merchant
Marine, Senate Committee on Commerce, Science, and Transportation,
U.S. Senate, Freight Railroads Preliminary Observations on Rates,
Competition, and Capacity Issues, Statement of JayEtta Z. Hecker,
Director, Physical Infrastructure Issues, GAO, GAO-06-898T
(Washington, DC: June, 21, 2006).
\184\ GAO, Freight Railroads: Industry Health Has Improved, but
Concerns about Competition and Capacity Should Be Addressed, GAO-07-
94 (Washington, DC: Oct. 6, 2006); GAO, Freight Railroads: Updated
Information on Rates and Other Industry Trends, GAO-07-291R Freight
Railroads (Washington, DC: Aug. 15, 2007). STB's final report,
entitled Report to the U.S. STB on Competition and Related Issues in
the U.S. Freight Railroad Industry, is expected to be completed
November, 1, 2008.
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Given the broad importance to the U.S. economy of meeting the
anticipated increase in freight rail demand, and the substantial
resources that seem likely to be focused on this cause, we believe that
overall freight rail capacity would not be a limiting factor to the
successful implementation of the biofuel requirements to meet the RFS2
standards. Evidence from the recent ramp up of ethanol use has also
shown that rail carriers are enthusiastically pursuing the shipment of
ethanol. Class 2 railroads have been particularly active in gathering
sufficient numbers of ethanol cars to allow Class 1 railroads to ship
ethanol by unit train. Likewise, we believe that that Class 2 railroads
and, to a lesser extent, the trucking industry, will play a key role in
the transportation of DDGs and other byproducts from regions with
concentrated ethanol production facilities to those with significant
livestock operations. Based on this recent experience, we believe that
ethanol will be able to compete successfully with other commodities in
securing its share of freight rail service.
While many changes to the overall freight rail system are expected
to occur irrespective of today's proposed rule, a number of ethanol-
specific modifications will be needed. For instance, a number of
additional rail terminals are likely to be configured for receipt of
unit trains of ethanol for further distribution by tank truck or other
means to petroleum terminals. The placement of ethanol unit train
receipt facilities at rail terminals would be particularly useful in
situations where petroleum terminals might find it difficult or
impossible to install their own ethanol rail receipt capability. We
anticipate that ethanol storage will typically be installed at rail
terminal ethanol receipt hubs over the long run. We do not anticipate
that the rail industry will experience substantial difficulty in
installing such ethanol-specific facilities once a clear long term
demand for ethanol in the target markets has been established to
justify the investment. However, the need for long-term demand to be
established prior to the construction of such facilities will likely
mean that the needed facilities will, at best, come on-line on a just-
in-time basis. This may lead to use of less efficient means of ethanol
transport in the short term. The ability to rely on transloading while
ethanol storage facilities at rail terminal ethanol receipt hub
facilities are constructed will speed the optimization of the
distribution of ethanol by rail by allowing the construction of ethanol
storage at rail terminal hubs to be delayed.
We estimate that a total of 44,000 rail cars would be needed to
distribute the volumes of ethanol and biodiesel that we project would
be used in 2022 to satisfy the RFS2 requirements.\185\ Our analysis of
ethanol and biodiesel rail car production capacity indicates that
access to these cars should not represent a serious impediment to
meeting the requirements under the RFS2 standards. Ethanol tank car
production has increased approximately 30% per year since 2003, with
over 21,000 tank cars expected to be produced in 2007. The volume of
these newly-produced tank cars, coupled with that of an existing tank
car fleet already dedicated to ethanol and biodiesel transport,
suggests that an adequate number of these tank cars will be in place to
transport the proposed renewable fuel volume requirements in the time
available.
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\185\ A discussion of how we arrived at the estimated number of
tank cars needed is contained in Section 4.2 of the DRIA.
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We request comment on the extent to which the rail system will be
able to deliver the additional volumes of ethanol and biodiesel that we
anticipate would be used in response to the RFS2 standards in a timely
and reliable fashion. A recently completed report by ORNL identifies
specific segments of the rail system which would likely see the most
significant increase in traffic due to increased shipments of ethanol
under the EISA.\186\
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\186\ ``Analysis of Fuel Ethanol Transportation Activity and
Potential Distribution Constraints'', prepared for EPA by Oak Ridge
National Laboratory, March 2009.
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6. Necessary Marine System Accommodations
The American Waterway's Association has expressed concerns about
the need to upgrade the inland waterway system in order to keep pace
with the anticipated increase in overall freight demand. The majority
of these concerns have been focused on the need to upgrade the river
lock system on the Mississippi River to accommodate longer barge tows
and on dredging inland waterways to allow for movement of fully loaded
vessels. We do not anticipate that a substantial fraction of renewable/
alternative fuels will be transported via these arteries. Thus, we do
not believe that the ability to ship ethanol/biodiesel by inland marine
will represent a serious barrier to the implementation of
implementation of the requirements under RFS2 standards. Substantial
quantities of the corn ethanol co-product dried distiller grains (DDG)
is expected to be exported from the Midwest via the Mississippi River
as the U.S. demand for DDG becomes saturated. We anticipate that the
volume of exported DDG would take the place of corn that would be
shifted from export to domestic use in the production of ethanol. Thus,
we do not expect the increase in DDG exports to result in a substantial
increase in river freight traffic. We request comment on the extent to
which marine transport may be used in the transport of cellulosic
ethanol feedstocks.
7. Necessary Accommodations to the Road Transportation System
Concerns have been raised regarding the ability of the trucking
industry to attract a sufficient number of drivers to handle the
anticipated increase in truck freight.\187\ The American Trucking
Association projected the need for additional 54,000 drivers each year.
We estimate that the growth in the use of biofuels through 2022 due to
the RFS2 standards would result in the need for a total of
approximately 3,000
[[Page 25007]]
additional trucks drivers. Given the relatively small number of new
truck drivers needed to transport the volumes of biofuels needed to
comply with the RFS2 standards through 2022 compared to the total
expected increase in demand for drivers over the same time period
(>750,000), we do not expect that the implementation of the RFS2
standards would substantially impact the potential for a shortage of
truck drivers. However, specially certified drivers are required to
transport ethanol and biodiesel because these fuels are classified as
hazardous liquids. Thus, there may be a heightened level of concern
about the ability to secure a sufficient number of such specially
certified tank truck drivers to transport ethanol and biodiesel. The
trucking industry is involved in efforts to streamline the
certification of drivers for hazardous liquids transport and more
generally to attract and retrain a sufficient number of new truck
drivers.
---------------------------------------------------------------------------
\187\ ``The U.S. Truck Driver Shortage: Analysis and
Forecasts'', Prepared by Global Insights for the American Trucking
Association, May 2005. http://www.truckline.com/NR/rdonlyres/E2E789CF-F308-463F-8831-0F7E283A0218/0/ATADriverShortageStudy05.pdf.
---------------------------------------------------------------------------
Truck transport of biofuel feedstocks to production plants and
finished biofuels and co-products from these plants is naturally
concentrated on routes to and from these production plants. This may
raise concerns about the potential impact on road congestion and road
maintenance in areas in the proximity of these facilities. We do not
expect that such potential concerns would represent a barrier to the
implementation of the RFS2 standards. The potential impact on local
road infrastructure and the ability of the road network to be upgraded
to handle the increased traffic load is an inherent part in the
placement of new biofuel production facilities. Consequently, we expect
that any issues or concerns would be dealt with at the local level.
We request comment on the extent to which satisfying the
requirements under the RFS2 standards might exacerbate the anticipated
shortage of truck drivers or lead to localized road congestion and
condition problems. Comment is further requested on the means to
mitigate such potential difficulties to the extent they might exist.
8. Necessary Terminal Accommodations
Terminals will need to install additional storage capacity to
accommodate the volume of ethanol/biodiesel that we anticipate will be
used in response to the RFS2 standards. Questions have been raised
about the ability of some terminals to install the needed storage
capacity due to space constraints and difficulties in securing
permits.\188\ Overall demand for fuel used in spark ignition motor
vehicles is expected to remain relatively constant through 2022. Thus,
much of the demand for new ethanol and biodiesel storage could be
accommodated by modifying storage tanks previously used for the
gasoline and petroleum-based diesel fuels that would displaced by
ethanol and biodiesel. The areas served by existing terminals also
often overlap. In such cases, one terminal might be space constrained
while another serving the same area may be able to install the
additional capacity to meet the increase in demand. Terminals with
limited ethanol storage (or no access to rail/barge ethanol shipments)
could receive truck shipments of ethanol from terminals with more
substantial ethanol storage (and rail/barge receipt) capacity. The
trend towards locating ethanol receipt and storage capability at rail
terminals located near petroleum terminals is likely to be an important
factor in reducing the need for large volume ethanol receipt and
storage facilities at petroleum terminals. In cases where it is
impossible for existing terminals to expand their storage capacity due
to a lack of adjacent available land or difficulties in securing the
necessary permits, new satellite storage or new separate terminal
facilities may be needed for additional ethanol and biodiesel storage.
However, we believe that there would be few such situations.
---------------------------------------------------------------------------
\188\ The Independent Fuel Terminal Operators Association
represents terminals in the Northeast.
---------------------------------------------------------------------------
Another question is whether the storage tank construction industry
would be able to keep pace with the increased demand for new tanks that
would result from today's proposal. The storage tank construction
industry recently experienced a sharp increase in demand after years of
relatively slack demand for new tankage. Much of this increase in
demand was due to the unprecedented increase in the use of ethanol.
Storage tank construction companies have been increasing their
capabilities which had been pared back during lean times.\189\ Given
the projected gradual increase in the need for biofuel storage tanks,
it seems reasonable to conclude that the storage tank construction
industry would be able to keep pace with the projected demand.
---------------------------------------------------------------------------
\189\ It currently may take 4 to 8 months to begin construction
of a storage tank after a contract is signed due to tightness in
construction assets and steel supply.
---------------------------------------------------------------------------
The RFG and anti-dumping regulations currently require certified
gasoline to be blended with denatured ethanol to produce E85. The
gasoline must meet all applicable RFG and anti-dumping standards for
the time and place where it is sold. We understand that some parties
may be blending butanes and or pentanes into gasoline before it is
blended with denatured ethanol in order to meet ASTM minimum volatility
specifications for E85 that were set to ensure proper drivability,
particularly in the winter.\190\ If terminal operators add blendstocks
to finished gasoline for use in manufacturing E85, the terminal
operator would need to register as a refiner with EPA and meet all
applicable standards for refiners.
---------------------------------------------------------------------------
\190\ ``Specification for Fuel Ethanol (Ed75-Ed85) for Spark-
Ignition Engines'', American Society for Testing and Materials
standard ASTM D5798.
---------------------------------------------------------------------------
Recent testing has shown that much of in-use E85 does not meet
minimum ASTM volatility specifications.\191\ However, it is unclear if
noncompliance with these specifications has resulted in a commensurate
adverse impact on drivability. This has prompted a re-evaluation of the
fuel volatility requirements for in-use E85 vehicles and whether the
ASTM E85 volatility specifications might be relaxed.\192\ For the
purpose of our analysis, we are assuming that certified gasoline
currently on hand at terminals can be used to make up the non-ethanol
portion of E85.\193\
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\191\ Coordinating Research Council (CRC) report No. E-79-2,
Summary of the Study of E85 Fuel in the USA Winter 2006-2007, May
2007. http://www.crcao.org/reports/recentstudies2007/E-79-2/E-79-2%20E85%20Summary%20Report%202007.pdf.
\192\ CRC Cold Start and Warm-up E85 Driveability Program,
http://www.crcao.com/about/Annual%20Report/2007%20Annual%20Report/Perform/CM-133.htm.
\193\ This is different from the approach taken in the refinery
modeling which assumed that special blendstocks would be used to
blend E85. A discussion of the refinery modeling can be found in
Section 4 of the DRIA.
---------------------------------------------------------------------------
We request comment on the extent that this will be the case in
light of the projected outcome of the ASTM process. Comment is
requested on the fraction of terminals that currently have butane/
pentane blending capability and the logistical/cost implications of
adding such capability including sourcing and transportation issues
associated with supplying these blending components to the terminal for
the purpose of blending E85 to ASTM specifications. We also seek
comment on whether we should include a separate section in the RFS2
regulations to specify the requirements for producing E85, and whether
we should provide E85 manufacturers who use blendstocks to produce E85
with any flexibilities in complying with the refiner requirements.\194\
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\194\ Certain accommodations for butane blenders into gasoline
were provided in a direct final rule published on December 15, 2005
entitled, ``Modifications to Standards and Requirements for
Reformulated and Conventional Gasoline Including Butane Blenders and
Attest Engagements'', 70 FR 74552.
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[[Page 25008]]
A significant challenge facing terminals and one that is currently
limiting the volume of ethanol that can be used is the ability to
receive ethanol by rail. Only a small fraction of petroleum terminals
currently have rail receipt capability and a number likely have space
constraints or are located too far from the rail system which prevents
the installation of such capability. The trend to locate ethanol unit
train destinations at rail terminals will help to alleviate these
concerns. Petroleum terminals within trucking distance of each other
are also likely to cooperate so that only one would need to install
rail receipt capability. Given the timeframe during which the projected
volumes of ethanol ramp up, we believe that these means can be utilized
to ensure that a sufficient number of terminals have access to ethanol
shipped by rail although some will need to rely on secondary shipment
by truck from large ethanol hub receipt facilities. We request comment
on the current rail receipt capability at terminals and the extent to
which petroleum terminals can be expected to install such capability.
Comment is also requested on the extent to which the installation of
ethanol receipt facilities at rail terminals can help to meet the need
to bring ethanol by rail to petroleum terminals. Our current analysis
estimated that half of the new ethanol rail receipt capability needed
to support the use of the projected ethanol volumes under the EISA
would be installed at petroleum terminals, and half would be installed
at rail terminals. A recently completed study by ORNL estimated that
all new ethanol rail receipt capability would be installed at existing
rail terminals given the limited ability to install such capability at
petroleum terminals.\195\ We intend to review our estimates regarding
the location of the additional ethanol rail receipt facilities for the
final rule in light of the ORNL study.
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\195\ ``Analysis of Fuel Ethanol Transportation Activity and
Potential Distribution Constraints'', prepared for EPA by Oak Ridge
National Laboratory, March 2009.
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9. Need for Additional E85 Retail Facilities
We estimate that an additional 24,250 E85 retail facilities would
be needed to facilitate the consumption of the additional amount of
ethanol that we project would be used by 2022 in response to the
requirements under the RFS2 standards.\196\ On average, this equates to
approximately 1,960 new E85 facilities that would need to be added each
year from 2009 through 2022 in order to satisfy this goal. This is a
very ambitious timeline given that there are less than 2,000 E85 retail
facilities in service today. Nevertheless, we believe the addition of
these numbers of new E85 facilities may be possible for the industries
that manufacture and install E85 retail equipment. Underwriters
Laboratories recently finalized its certification requirements for E85
retail equipment.\197\ Equipment manufactures are currently evaluating
the changes that will be needed to meet these requirements.\198\
However, we anticipate the needed changes will not substantially
increase the difficulty in the manufacture of such equipment compared
to equipment which is specifically manufactured for dispensing E85
today.
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\196\ See Section 1.6 of the DRIA for a discussion of the
projected number of E85 refueling facilities that would be needed.
There would need to be a total of 28,750 E85 retail facilities,
4,500 of which are projected to have been placed in service absent
the RFS2 standards.
\197\ See http://ulstandardsinfonet.ul.com/outscope/0087A.html.
\198\ All dispenser equipment except the hose used to dispense
fuel to the vehicle has been evaluated by UL. Once suitable hoses
have been evaluated, a complete E85 dispenser system can be
certified by UL.
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We estimate that the cost of installing E85 refueling equipment
will average $122,000 per facility which equates to $3 billion by
2022.\199\ These costs include the installation of an underground
storage tank, piping, dispensers, leak detection, and other ancillary
equipment that is compatible with E85.\200\ Our E85 facility cost
estimates are based on input from fuel retailers and other parties with
familiarity in installing E85 compatible equipment. We understand that
a certification has yet to be finalized by Underwriters Laboratories
for a complete equipment package necessary to store/dispense E85 at a
retail facility.\201\ Thus, there is some uncertainty regarding the
type of equipment that will be needed for compliance with the E85
equipment certification requirements, and the associated costs.
Nevertheless, we believe that the E85 equipment that is eventually
certified for use will not be substantially different from that on
which our cost estimates are based.\202\
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\199\ See Section 4.2 of the DRIA for a discussion of E85
facility costs. These costs include the installation of 2 pumps with
4 E85 refueling positions at 40% of new facilities, and 1 pump with
2 refueling positions at 60% of new facilities. A sensitivity case
was evaluated where it was assumed that all new E85 facilities would
install 3 pumps with 6 refueling positions. The cost per facility
under this sensitivity case is $166,000.
\200\ 40 CFR 280.32 requires that underground storage tank
systems must be made of or lined with materials that are compatible
with the substance stored in the system.
\201\ Underwriters Laboratories recently finalized their
requirements for the certification of E85 compatible equipment. No
certifications have been completed to date, because of the time
needed to complete the application for certification including
necessary testing.
\202\ All retail dispenser components except the hose that
connects the nozzle to the dispenser have been evaluated by UL. Once
such hoses have been evaluated by UL, a certification for the
complete fuel dispenser assembly may be finalized by UL.
---------------------------------------------------------------------------
Petroleum retailers expressed concerns about their ability to bear
the cost installing the needed E85 refueling equipment. Today's
proposal does not contain a requirement for retailers to carry E85. We
understand that retailers will only install E85 facilities if it is
economically advantageous for them to do so and that they will price
their E85 and E10 in a manner to recover these costs. While the $3
billion total cost for E85 refueling facilities is a substantial sum,
it equates to just 1.5 cents per gallon of E85 throughput.\203\
Therefore, we do not believe that the cost of installing E85 refueling
equipment will represent an undue burden to retailers given the very
large projected consumer demand for E85.
---------------------------------------------------------------------------
\203\ E85 facility costs were amortized over 15 years at 7% and
the costs spread over the projected volume of E85 dispensed.
---------------------------------------------------------------------------
Petroleum retailers also expressed concern regarding their ability
to discount the price of E85 sufficiently to persuade flexible fuel
vehicle owners to choose E85 given the lower energy density of ethanol.
This issue is discussed in Section V.D.2.e. of today's preamble.
D. Ethanol Consumption
1. Historic/Current Ethanol Consumption
Ethanol and ethanol-gasoline blends have a long history as
automotive fuels. However, cheap gasoline/blendstocks kept ethanol from
making a significant presence in the transportation sector until the
end of the 20th century when environmental regulations and tax
incentives helped to stimulate growth.
In 1978, the U.S. passed the Energy Tax Act which provided an
excise tax exemption for ethanol blended into gasoline that would later
be modified through subsequent regulations.\204\ In the 1980s, EPA
initiated a phase-out of leaded gasoline which created some interest in
ethanol as a gasoline
[[Page 25009]]
oxygenate. Upon passage of the 1990 CAA amendments, states implemented
winter oxygenated fuel (``oxyfuel'') programs to monitor carbon
monoxide emissions. EPA also established the reformulated gasoline
(RFG) program to help reduce emissions of smog-forming and toxic
pollutants. Both the oxyfuel and RFG programs called for oxygenated
gasoline. However, petroleum-derived ethers, namely methyl tertiary
butyl ether (MTBE), dominated oxygenate use until drinking water
contamination concerns prompted a switch to ethanol. Additional support
came in 2004 with the passage of the Volumetric Ethanol Excise Tax
Credit (VEETC). The VEETC provided domestic ethanol blenders with a
$0.51/gal tax credit, replacing the patchwork of existing
subsidies.\205\ The phase-out of MTBE and the introduction of the VEETC
along with state mandates and tax incentives created a growing demand
for ethanol that surpassed the traditional oxyfuel and RFG markets. By
the end of 2004, not only was ethanol the lead oxygenate, it was found
to be blended into a growing number of states' conventional
gasoline.\206\
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\204\ Gasohol, a fuel containing at least 10% biomass-derived
ethanol, received a partial exemption from the federal gasoline
excise tax. This exemption was implemented in 1979 and a blender's
tax credit and a pure alcohol fuel credit were added to the mix in
1980.
\205\ The 2008 Farm Bill, discussed in more detail in Section
V.B.2.b, replaces the $0.51/gal ethanol blender credit with a $0.45/
gal corn ethanol blender credit and also introduces a $1.01/gal
cellulosic biofuel producer credit. Both credits are effective
January 1, 2009.
\206\ Based on 2004 Federal Highway Association (FHWA) State
Gasohol Report less estimated RFG and oxyfuel ethanol usage based on
EPA's 2004 RFG Fuel Survey results and knowledge of state oxyfuel
programs and fuel oxygenates. For more on historical ethanol usage
by state and fuel type, refer to Section 1.7.1.1 of the DRIA.
---------------------------------------------------------------------------
In the years that followed, rising crude oil prices and other
favorable market conditions continued to drive ethanol usage. In May
2007, EPA promulgated a Renewable Fuel Standard (``RFS1'') in response
to EPAct. The RFS1 program set a floor for renewable fuel use reaching
7.5 billion gallons by 2012, the majority of which was ethanol. The
country is currently on track for exceeding the RFS1 requirements and
meeting the introductory years of today's proposed RFS2 program. For a
summary of the growth in U.S. ethanol usage over the past decade, refer
to Table V.D.1.-1.
Table V.D.1-1--U.S. Ethanol Consumption (Including Imports)
------------------------------------------------------------------------
Total ethanol use \a\
-------------------------
Year Trillion
BTU Bgal
------------------------------------------------------------------------
1999.......................................... 120 1.4
2000.......................................... 138 1.6
2001.......................................... 144 1.7
2002.......................................... 171 2.0
2003.......................................... 233 2.8
2004.......................................... 292 3.5
2005.......................................... 334 4.0
2006.......................................... 451 5.3
2007.......................................... 566 6.7
2008.......................................... 792 9.4
------------------------------------------------------------------------
\a\ EIA Monthly Energy Review March 2009 (Table 10.2).
Through the years, there have also been several policy initiatives
to increase the number of flexible fuel vehicles (FFVs) capable of
consuming up to 85 volume percent ethanol blends (E85). The Alternative
Motor Vehicle Fuels Act of 1988 provided automakers with Corporate
Average Fuel Economy (CAFE) credits for producing alternative-fuel
vehicles, including FFVs as well as CNG and propane vehicles.
Furthermore, the Energy Policy Act of 1992 required government fleets
to begin purchasing alternative-fuel vehicles, and the majority of
fleets chose FFVs.\207\ As a result of these two policy measures, there
are over 7 million FFVs on the road today.\208\ These vehicles increase
our nation's ethanol consumption potential beyond what is capable with
conventional vehicles. However, most FFVs are currently refueling on
conventional gasoline (E0 or E10) due to limited E85 availability and
the fact that E85 is typically priced 20-30 cents per gallon higher
than gasoline on an energy equivalent basis. As such, we are not
currently tapping into the full ethanol consumption potential of our
FFV fleet. However, we expect refueling patterns to change in the
future under the RFS2 program.
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\207\ Source: June 23, 2008 Federal Times, Special Report: Fleet
Management.
\208\ Source: DOE Energy Efficiency and Renewable Energy
(worksheet available at www.eere.energy.gov/afdc/data/index.html.)
---------------------------------------------------------------------------
2. Increased Ethanol Use under RFS2
To meet the RFS2 standards, ethanol consumption will need to be
much higher than both today's levels and those projected to occur
absent RFS2. The Energy Information Administration (EIA) projected that
under business-as-usual conditions, ethanol usage would grow to just
over 13 billion gallons by 2022.\209\ This represents significant
growth from today's usage, however, this volume of ethanol is capable
of being consumed by today's vehicle fleet albeit with some fuel
infrastructure improvements.\210\ Although EIA projected a small
percentage of ethanol to be blended as E85 in 2022, 13 billion gallons
of ethanol could also be consumed by displacing about 90% of our
country's forecasted gasoline energy demand with E10. The maximum
amount of ethanol our country is capable of consuming as E10 compared
to the projected RFS2 ethanol volumes is shown below in Figure V.D.2-
1.\211\
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\209\ Source: EIA Annual Energy Outlook 2007, Table 17.
\210\ For more information on distribution accommodations, refer
to Section V.C.
\211\ The maximum E10 volumes are a function of the gasoline
energy demand reported in EIA's Annual Energy Outlook 2009, Table 2
adjusted with lower heating values.
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[[Page 25010]]
[GRAPHIC] [TIFF OMITTED] TP26MY09.006
As shown in Figure V.D.2-1, under the proposed RFS2 program, we are
projected to hit the E10 ``blend wall'' of about 14.5 billion gallons
of ethanol by 2013. This volume corresponds to 100% E10 nationwide.
However, if gasoline demand falls, or if E10 cannot get distributed
nationwide, the nation could hit the blend wall sooner. Regardless, to
get beyond the blend wall and consume more than 14-15 billion gallons
of ethanol, we are going to need to see significant increases in the
number FFVs on the road, the number of E85 retailers, and the FFV E85
refueling frequency. In the subsections that follow, we will highlight
the variables that impact our nation's ethanol consumption potential
and, more specifically, what measures the market may need to take in
order to consume 34 billion gallons of ethanol by 2022 (assuming the
cellulosic biofuel standard and the majority of the advanced biofuel
standard are met with ethanol).
---------------------------------------------------------------------------
\212\ Based on the assumption that the cellulosic biofuel
standard and the majority of the advanced biofuel standard would be
met with ethanol.
---------------------------------------------------------------------------
As explained in Section V.A.2, our primary RFS2 analysis focuses on
ethanol as the main biofuel in the future.\213\ In addition, from an
ethanol consumption standpoint, we have focused on an E10/E85 world.
While E0 is capable of co-existing with E10 and E85 for a while, we
assumed that E10 would replace E0 as expeditiously as possible and that
all subsequent ethanol growth would come from E85. Furthermore, for our
primary analysis, we assumed that no ethanol consumption would come
from the mid-level ethanol blends (i.e., E15 or E20) as they are not
currently approved for use in non-FFVs. However, in Section V.D.3
below, we discuss the potential approval pathways for mid-level ethanol
blends and the volume implications.
---------------------------------------------------------------------------
\213\ For consideration of other biofuels, refer to Section
V.D.3.d.
---------------------------------------------------------------------------
We acknowledge that, if approved, mid-level ethanol blends could
help the nation meet the proposed RFS2 volume requirements. First, non-
FFVs could consume more ethanol per gallon of ``gasoline''. This could
result in greater ethanol consumption nationwide. In addition, mid-
level blends could allow gasoline retailers to continue to price
ethanol relative to gasoline (as it currently is for E10). For these
reasons, it is possible that mid-level ethanol blends could help the
nation get beyond the E10 blend wall. However, as explained in Section
V.D.3.b, there are numerous actions that would need to be taken to
bring mid-level ethanol blends to market. In addition, mid-level
ethanol blends alone (even if made available nationwide) are not
capable of fulfilling the RFS2 requirements in later years. We would
essentially hit another blend wall 1-6 years later depending on the
intermediate blend, how quickly it could be brought to market, and how
widely mid-level ethanol blends were distributed at retail stations
nationwide. Nevertheless, this time could be very valuable when it
comes to expanding E85/FFV infrastructure and/or commercializing other
non-ethanol cellulosic biofuels.
Regardless, our primary analysis focuses on an E10/E85 world
because mid-level ethanol blends are not currently approved for use in
conventional gasoline vehicles and nonroad equipment. Before usage
could be legalized, as discussed more in Section V.D.3 below, EPA would
need to grant a waiver declaring that mid-level blends are
substantially similar or ``sub-sim'' to gasoline or perhaps even
reinterpret the meaning of ``sub-sim''. While such a waiver has not yet
been granted, several organizations/agencies are performing vehicle
emission testing and investigating other impacts of mid-
[[Page 25011]]
level blends.\214\ Therefore, as a sensitivity analysis, we have
analyzed what might need to be done to bring mid-level ethanol blends
to market (should a sub-sim waiver be approved) and the extent to which
such blends could help our nation meet the RFS2 ethanol standards, at
least in the near term. Finally we end our ethanol usage discussion by
looking at other strategies for getting beyond the E10 blend wall.
---------------------------------------------------------------------------
\214\ For more information on mid-level ethanol blends testing,
refer to Section V.D.3.b.
---------------------------------------------------------------------------
a. Projected Gasoline Energy Demand
The maximum amount of ethanol our country is capable of consuming
in any given year is a function of the total gasoline energy demanded
by the transportation sector. Our nation's gasoline energy demand is
dependent on the number of gasoline-powered vehicles on the road, their
average fuel economy, vehicle miles traveled (VMT), and driving
patterns. For analysis purposes, we relied on the gasoline energy
projections reported by EIA in AEO 2008.\215\ Unlike AEO 2007, AEO 2008
takes the fuel economy improvements set by EISA into consideration and
also assumes a slight dieselization of the vehicle fleet. The result is
a 15% reduction in the projected 2022 gasoline energy demand from AEO
2007 to AEO 2008.\216\ EIA basically has gasoline energy demand
(petroleum-based gasoline plus ethanol) flattening out, and even
slightly decreasing, as we move into the future and implement the EISA
vehicle standards.\217\
---------------------------------------------------------------------------
\215\ For blend wall discussions, we rely on the most recent AEO
2009 projections. However for our detailed ethanol consumption
analysis presented in this section (and in more detail in Section
1.7.1 of the DRIA), we relied on AEO 2008.
\216\ EIA Annual Energy Outlook 2007 & 2008, Table 2.
\217\ For more information on gasoline energy projections, refer
to Section 1.7.1.2.1 of the DRIA.
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b. Projected Growth in Flexible Fuel Vehicles
According to DOE's Department of Energy Efficiency and Renewable
Energy, there are currently over 7 million FFVs on the road today
capable of consuming E85.\218\ And that number is growing steadily.
Automakers are incorporating more and more FFVs into their light-duty
production plans. While the FFV system (i.e., fuel tank, sensor,
delivery system, etc.) used to be an option on some vehicles, most FFV
producers are moving in the direction of converting entire product
lines over to E85-capable systems. Still, the number of FFVs that will
be manufactured and purchased in future years is uncertain. For our
cost analysis, we examined several different FFV production scenarios.
But for our ethanol usage analysis, we focused on one primary FFV
scenario, described in more detail below.\219\
---------------------------------------------------------------------------
\218\ DOE Energy Efficiency and Renewable Energy August 2008
estimate (worksheet available at www.eere.energy.gov/afdc/data/index.html).
\219\ For more on the FFV production scenarios we considered,
refer to Section 1.7.1.2.2 of the DRIA.
---------------------------------------------------------------------------
In response to President Bush's ``20-in-10'' plan of reducing
American gasoline usage by 20% in 10 years, domestic automakers
responded with aggressive FFV production goals. General Motors, Ford
and Chrysler (referred to hereafter as ``The Detroit 3'') announced
plans to produce 50% FFVs by 2012.\220\ And despite the current state
of the economy and the auto industry, it appears U.S. automakers are
still moving forward with their FFV production plans.\221\ Assuming
that The Detroit 3 continue to maintain 50% market share and that total
vehicle sales remain around 16 million per year, at least 4 million
FFVs will be produced by the 2012 model year. Based on 2008 offerings,
we assumed that approximately 80% of The Detroit 3's FFV production
commitment would be met by light-duty trucks and the remaining 20%
would be cars.222 223 We also assumed that all the FFVs in
existence today were produced by The Detroit 3 (and therefore share the
same aforementioned car/truck ratio) and that production would ramp up
linearly beginning in 2008 to reach the 2012 commitment.
---------------------------------------------------------------------------
\220\ Ethanol Producer Magazine, ``View From the Hill.'' July
2007.
\221\ Ethanol Producer Magazine, ``Automakers Maintain FFV
Targets in Bailout Plans.'' February 2009.
\222\ NEVC 2008 Purchasing Guide for Flexible Fuel Vehicles.
\223\ Several of the FFV assumptions may need to be revised for
the FRM in light of recent events.
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Although non-domestic automakers have not made any official FFV
production commitments, Nissan, Mercedes, Izuzu, and Mazda all included
at least one flexible fuel vehicle in their 2008 model year
offerings.\224\ And we anticipate that additional FFVs (or FFV options)
will be added in the future. Ultimately, we predict that non-domestic
FFV production could be as high as 25%, or about 2 million FFVs per
year. While we are not forecasting an official FFV production
commitment from the non-domestic automakers, we believe that this
represents an aggressive, yet reasonable FFV production estimate for
analysis purposes. Furthermore, based on current offerings, we assumed
that the majority of non-domestic FFV production would be trucks. With
respect to timing, we expect that the non-domestic automakers would
ramp up FFV production later than The Detroit 3. For analysis purposes,
we assumed that non-domestic automakers would ramp up FFV production
beginning in 2013, and like The Detroit 3, it would take about five
years for them to reach their FFV production goals (or in this case,
the assumed 25% production level)
---------------------------------------------------------------------------
\224\ Ibid.
---------------------------------------------------------------------------
Based on these FFV assumptions and forecasted vehicle phase-out,
VMT, and fuel economy estimates provided by EPA's MOVES Model, we
calculate that the maximum percentage of fuel (gasoline/ethanol mix)
that could feasibly be consumed by FFVs in 2022 would be about 30%. For
more information on our FFV analysis, refer to Section 1.7.1.2.2 of the
DRIA.
c. Projected Growth in E85 Access
According to the National Ethanol Vehicle Coalition (NEVC), there
are currently over 1,900 retailers offering E85 in 45 states plus the
District of Columbia.\225\ While this represents significant industry
growth, it still only translates to about 1% of U.S. retail stations
nationwide carrying the fuel.\226\ As a result, most FFV owners clearly
do not have reasonable access to E85. For our FFV/E85 analysis, we have
defined ``reasonable access'' as one-in-four pumps offering E85 in a
given area.\227\ Accordingly, just over 4% of the nation currently has
reasonable access to E85, up from 3% in 2007 (based on a mid-year NEVC
E85 pump estimate).\228\
---------------------------------------------------------------------------
\225\ NEVC FYI Newsletter: Volume 15, Issue 5: March 9, 2009.
\226\ Based on National Petroleum News gasoline station estimate
of 161,768 in 2008.
\227\ For a more detailed discussion on how we derived our one-
in-four reasonable access assumption, refer to Section 1.6 of the
DRIA. For the distribution cost implications as well as the cost
impacts of assuming reasonable access is greater than one-in-four
pumps, refer to Section 4.2 of the DRIA.
\228\ Computed as percent of stations with E85 (1,963/161,768 as
of March 2009 or 1,251/164,292 as of July 2007) divided by 25% (one-
in-four stations).
---------------------------------------------------------------------------
There are a number of states promoting E85 usage by offering FFV/
E85 awareness programs and/or retail pump incentives. A growing number
of states are also offering infrastructure grants to help expand E85
availability. Currently, nine Midwest states have adopted a progressive
Energy Security and Climate Stewardship Platform.\229\
[[Page 25012]]
The platform includes a Regional Biofuels Promotion Plan with a goal of
making E85 available at one third of all stations by 2025. In addition,
on July 31, 2008, Congresswoman Stephanie Herseth Sandlin (D-SD) and
John Shimkus (R-IL) introduced The E85 and Biodiesel Access Act that
would amend IRS tax code and increase the existing federal income tax
credit from $30,000 or 30% of the total cost of improvements to
$100,000 or 50% of the total cost of needed alternative fuel equipment
and dispensing improvements.\230\ While not signed into law, such a tax
credit could provide a significant retail incentive to expand E85
infrastructure.
---------------------------------------------------------------------------
\229\ The following states have adopted the plan: Indiana,
Kansas, Michigan, Minnesota, Ohio, South Dakota, Wisconsin, Iowa,
and most recently, North Dakota. For more information, visit: http://www.midwesterngovernors.org/resolutions/Platform.pdf.
\230\ A copy of House Rule 6734 can be accessed at: http://www.e85fuel.com/news/2008/080108_shimkus_release/shimkus.pdf.
---------------------------------------------------------------------------
Given the growing number of state infrastructure incentives and the
proposed Federal alternative fuel infrastructure subsidy, it is clear
that E85 infrastructure will continue to expand in the future. However,
the extent to which nationwide E85 access will grow is difficult to
predict, let alone quantify. For analysis purposes, as a practical
upper bound, we have selected 70% by 2022. This is roughly equivalent
to all urban areas in the United States offering reasonable (one-in-
four-station) access to E85.\231\ We are not concluding that the
percentage of the nation with reasonable access to E85 could not exceed
70% (as a sensitivity, we also modeled the cost impacts of nationwide
access to E85) or that availability would necessarily be concentrated
in urban areas. However, for analysis purposes, we believe that 70% is
a good surrogate for a practical portion of the country that could have
reasonable one-in-four access to E85 by 2022 under the proposed RFS2
program. On average, this translates to about 18% of retail stations
nationwide offering E85. As discussed in Section V.C, we believe this
is feasible based on our assessment of the distribution infrastructure
capabilities. For more information on the projected growth in E85
access, refer to Section 1.7.1.2.3 of the DRIA.
---------------------------------------------------------------------------
\231\ For this analysis, we've defined ``urban'' as the top 150
metropolitan statistical areas according to the U.S. census and/or
counties with the highest VMT projections according the EPA MOVES
model, all RFG areas, winter oxy-fuel areas, low-RVP areas, and
other relatively populated cities in the Midwest.
---------------------------------------------------------------------------
d. Required Increase in E85 Refueling Rates
As mentioned above, there were approximately 7 million FFVs on the
road in 2008. If all FFVs refueled on E85 100% of the time, this would
translate to about 6.5 billion gallons of E85 use.\232\ However, E85
usage was only around 12 million gallons in 2008.\233\ This means that,
on average, FFV owners were only tapping into about 0.2% of their
vehicles' E85/ethanol usage potential last year. Assuming that only 4%
of the nation had reasonable one-in-four access to E85 in 2008 (as
discussed above), this equates to an estimated 5% E85 refueling
frequency for those FFVs that had reasonable access to the fuel.
---------------------------------------------------------------------------
\232\ Based on the assumption that FFV owners travel
approximately 12,000 miles per year and get about 18 miles per
gallon on average under actual in-use driving conditions. For more
information, refer to Section 1.7.1.2.4 of the DRIA.
\233\ EIA Annual Energy Outlook 2009, Table 17.
---------------------------------------------------------------------------
There are several reasons for today's low E85 refueling frequency.
For starters, many FFV owners may not know they are driving a vehicle
that is capable of handling E85. As mentioned earlier, more and more
automakers are starting to produce FFVs by engine/product line, e.g.,
all 2008 Chevy Impalas are FFVs.\234\ Consequently, consumers
(especially brand loyal consumers) may inadvertently buy a flexible
fuel vehicle without making a conscious decision to do so. And without
effective consumer awareness programs in place, these FFV owners may
never think to refuel on E85. In addition, FFV owners with reasonable
access to E85 and knowledge of their vehicle's E85 capabilities may
still not choose to refuel on E85. They may feel inconvenienced by the
increased E85 refueling requirements. Based on its lower energy
density, FFV owners will need to stop to refuel 21% more often when
filling up on E85 over E10 (and likewise, 24% more often when refueling
on E85 over conventional gasoline).\235\ In addition, some FFV owners
may be deterred from refueling on E85 out of fear of reduced vehicle
performance or just plain unfamiliarity with the new motor vehicle
fuel. However, as we move into the future, we believe the biggest
determinant will be price--whether E85 is priced competitively with
gasoline based on its reduced energy density and the fact that you need
to stop more often, drive a little further to find an E85 station, and
depending on the retail configuration, wait in longer lines to fill up
on E85.
---------------------------------------------------------------------------
\234\ NEVC, ``2008 Purchasing Guide for Flexible Fuel
Vehicles.'' Refers to all mass produced 3.5 and 3.9L Impalas.
However, it is our understanding that consumers may still place
special orders for non-FFVs.
\235\ Based on our assumption that denatured ethanol has an
average lower heating value of 77,930 BTU/gal and conventional
gasoline (E0) has average lower heating value of 115,000 BTU/gal.
For analysis purposes, E10 was assumed to contain 10 vol% ethanol
and 90 vol% gasoline. Based on EIA's AEO 2008 report, E85 was
assumed to contain 74 vol% ethanol and 26 vol% gasoline on average.
---------------------------------------------------------------------------
To comply with the proposed RFS2 program and consume 34 billion
gallons of ethanol by 2022, not only would we need more FFVs and more
E85 retailers, we would need to see a significant increase in the
current FFV E85 refueling frequency. Based on the FFV and retail
assumptions described above in subsections (b) and (c), our analysis
suggests that FFV owners with reasonable access to E85 in 2022 would
need to fill up on it 74% of the time, a significant increase from
today's estimated 5% refueling frequency. Were there to be fewer FFVs
in the fleet, the E85 refueling frequency would need to be even higher.
Similarly, with more FFVs in the fleet, the E85 refueling frequency
could be lower and still meet the proposed RFS2 requirements. However,
even with an FFV mandate, our analysis suggests that we would need to
see an increase from today's average FFV E85 refueling frequency. In
order for this to be possible, there will need to be an improvement in
the current E85/gasoline price relationship.
e. Market Pricing of E85 Versus Gasoline
According to a recent online fuel price survey, E85 is currently
priced almost 30 cents per gallon higher than conventional gasoline on
an energy-equivalent basis.\236\ To increase our nation's E85 refueling
frequency to the levels described above, E85 needs to be priced
competitively with (if not lower than) conventional gasoline based on
its reduced energy content, increased time spent at the pump, and
limited availability. Our analysis, described in more detail in Section
1.7.1.2.5 of the DRIA, suggests that E85 would need to be priced about
one-third lower than gasoline at retail (based on 2006 prices) in order
for it to be cost-competitive. As expected, higher crude prices could
make E85 look slightly more attractive while lower crude oil prices
could make E85 look less attractive.
---------------------------------------------------------------------------
\236\ Based on average E85 and regular unleaded gasoline prices
reported at http://www.fuelgaugereport.com/ on April 23, 2009.
---------------------------------------------------------------------------
In Brazil, charts are posted at gas stations informing flex-fuel
vehicle owners whether it makes sense to fill up on ``gasoline''
(containing 20-25% denatured anhydrous ethanol) \237\ or ``alcohol''
(100% denatured hydrous ethanol) based on the price and relative energy
density of each. However, in the U.S., FFV owners will likely be on
their
[[Page 25013]]
own for figuring out which fuel is more economical.
---------------------------------------------------------------------------
\237\ The government-mandated gasoline ethanol content was 25%
as of July 2007. Source: F.O. Licht World Ethanol & Biofuels Report
Vol. 5 No. 21 July 9, 2007.
---------------------------------------------------------------------------
Although in some areas of the country E85 is already priced
significantly lower than gasoline, this is a far cry from a nationwide
trend. And as we move into the future and incorporate cellulosic
ethanol (a fuel that is currently more expensive to produce than corn
ethanol), it may be even more difficult to produce ethanol for a price
that the market would accept. However, a number of measures could be
taken to help encourage FFV E85 refueling.
The first is increased consumer awareness. To maximize ethanol
usage, it is important that FFV owners are aware of their vehicle's
fueling capabilities, i.e., that their vehicle is capable of refueling
on E85. It is equally important that FFV owners are aware of E85
refueling outlets that may be available to them. Automakers and/or car
dealerships could notify FFV owners of E85 stations in their area.
Together, increased automaker and retail awareness could help increase
our nation's E85 throughput potential. However, in order for consumers
to actually choose E85 over conventional gasoline on a regular basis,
there needs to be a marked price incentive at the pump.
Current federal and most state tax code does not differentiate
between ethanol sold as E10 and as E85. As of July 2008, state excise
taxes were reported to account for more than $0.18 per gallon of
gasoline (on average).\238\ However, there are a number of states
(e.g., Illinois, Indiana, North Dakota, and South Dakota) that
currently waive or discount excise taxes on E85. This type of fuel tax
structure helps contribute to a retail price relationship that favors
E85 over conventional gasoline.\239\ If states continue to waive/reduce
E85 fuel taxes under RFS2, this could help increase the FFV E85
refueling frequency. As expected, this would have the greatest impact
on ethanol consumption in the areas of the country with the most FFVs.
---------------------------------------------------------------------------
\238\ Source: The American Petroleum Institute July 2008
Gasoline Tax Report available at: http://www.api.org/statistics/fueltaxes/upload/July_2008_gasoline_and_diesel_summary_pages.pdf.
\239\ Source: DOE Energy Efficiency and Renewable Energy Web
site (http://www.eere.energy.gov/).
---------------------------------------------------------------------------
The E10/E85 price relationship could also be modified by the
refining industry. Under the proposed program, gasoline refiners (as
well as importers) would be required to purchase RINs to demonstrate
that sufficient volumes of renewable/alternative fuels were used to
meet their volume obligations. This could provide an incentive for
these parties to take the steps necessary to ensure adequate ethanol
use levels to facilitate compliance. One potential action that refiners
might take to ensure a sufficient RIN supply would be to subsidize the
price of the ethanol used to manufacture E85. Such a subsidy might be
financed by an increase in their selling price of gasoline. In
addition, refiners with marketing arms could adjust the retail price
relationship of E10 in E85 in way that encourages E85 throughput while
still maintaining the same average net profit. However, a relatively
small proportion of refiners market their own gasoline and thus have
the ability to make retail price adjustments. Consequently, relying
solely on market mechanisms may create some competitive concerns. We
request comment on viable and cooperative ways refiners and gasoline
retailers could promote E85 throughput to meet the proposed RFS2
requirements.
3. Other Mechanisms for Getting Beyond the E10 Blend Wall
a. Mandate for FFV Production
One way to increase ethanol usage under RFS2 would be if there were
more FFVs in the fleet. As described above, our primary analysis is
based on the assumption that The Detroit 3 would follow through with
their commitment to produce 50% FFVs by 2012 and the non-domestic
automakers would ramp up FFV production beginning in 2013 and produce
25% FFVs by 2017. Based on the projected number of FFVs in the fleet
(and our E85 infrastructure growth assumptions), FFV owners with
reasonable one-in-four access to E85 would need to refuel on it 74% of
the time. To achieve this optimistic refueling frequency, we believe
there would need to be significant improvements to the E10/E85 price
relationship.
One way to reduce the required FFV E85 refueling frequency (and in
turn decrease some of the pressure off E85 prices) would be to further
increase the number of FFVs in the fleet. While EPA does not have the
authority to require automakers to produce FFVs, there are a number of
bills in Congress that are set out to do just that. On July 22, 2008
Senator Sam Brownback (R-KS) on behalf of himself and Senators Susan
Collins (R-ME), Joseph Lieberman (I-CT), Ken Salazar (D-CO), and John
Thune (R-SD) introduced the Open Fuel Standard Act of 2008, a bill that
calls for 50% of the U.S. vehicle fleet to be FFVs capable of using
high blends of ethanol or methanol (in addition to gasoline) by 2012.
This number would grow to 80% by 2015.\240\ A similar FFV bill was
introduced by Eliot Engel (D-NY) in the House on July 22, 2008.\241\
---------------------------------------------------------------------------
\240\ Refer to Senate Bill 3303 which can be found at: http://thomas.loc.gov/cgi-bin/query/z?c110:S.3303.
\241\ Refer to House Rule 6559 which can be found at: http://thomas.loc.gov/cgi-bin/bdquery/z?d110:H.R.6559.
---------------------------------------------------------------------------
Since a future congressional mandate on FFV production in being
discussed, we have modeled the impact that such a mandate could have on
the RFS2 program. For our sensitivity analysis, we found that if
automakers were required to make all light-duty vehicles E85-capable by
2015 (and our same E85 infrastructure growth assumptions applied), FFV
owners with reasonable one-in-four access to E85 would only need to
refuel on it 33% of the time. This represents a smaller increase from
today's estimated 5% refueling rate. However, implementing such a FFV
mandate would have significant cost implications on the auto industry
and would still not provide certainty that FFV owners would fuel on
E85. For more information on this analysis, as well as other FFV
production scenarios we considered, refer to Section 1.7.1.2.2 of the
DRIA.
b. Waiver of Mid-Level Ethanol Blends (E15/E20)
For our primary ethanol usage analysis, we considered that there
would only be two fuels in the future, E10 and E85. And as explained in
Section V.D.2, we believe it is feasible to consume 34 billion gallons
of ethanol by 2022 given growth in FFV production and E85 availability
and projected improvements in the current E10/E85 price relationship.
However, several organizations and government entities are
interested in increasing the concentration of ethanol beyond the
current 10% limit in the commercial gasoline pool. Section 211(f)(1) of
the Clean Air Act prohibits the introduction into commerce, or increase
in the concentration in use of, gasoline or gasoline additives for use
in motor vehicles unless they are substantially similar to the gasoline
or gasoline additives used in the certification of new motor vehicles
or motor vehicle engines. EPA may grant a waiver of this prohibition
under Section 211(f)(4) provided that the fuel or fuel additive ``will
not cause or contribute to a failure of any emission control device or
system (over the useful life of the motor vehicle, motor vehicle
engine, nonroad engine or nonroad vehicle in which the device or system
is used) to achieve compliance by the vehicle or engine with the
emission standards to
[[Page 25014]]
which it has been certified.'' The most recent ``substantially
similar'' interpretive rule for unleaded gasoline presently allows
oxygen content up to 2.7% by weight for certain ethers and
alcohols.\242\ E10 contains approximately 3.5% oxygen by weight, which
makes a gasoline-ethanol blend with ten% ethanol not ``substantially
similar'' to certification fuel under the current interpretation.\243\
Since any mid-level blend would have a greater than allowed oxygen
content, any mid-level blend would need to have a waiver under Section
211(f)(4) of the CAA in order to be sold commercially.
---------------------------------------------------------------------------
\242\ 73 FR 22277 (April 25, 2008).
\243\ Gas Plus, Inc. submitted an application for a 211(f)(4)
waiver for E10 which was granted, see 44 FR 20777 (April 6, 1979).
---------------------------------------------------------------------------
Before EPA grants a 211(f)(4) waiver for a new fuel or fuel
additive, an applicant must prove that the new fuel or fuel additive
will meet the waiver requirements outlined in the statute. EPA has
required that applicants provide vehicle/engine testing for tailpipe
emissions, evaporative emissions, materials compatibility, and
driveability. Testing needs to include emissions over the full useful
life of vehicle and equipment. Several interested parties are
investigating the impact that mid-level ethanol blends (e.g., E15 or
E20) may have on these areas among others (i.e. catalyst, engine, and
fuel system durability, and onboard diagnostics). In order to use the
information collected for waiver application purposes, the mid-level
ethanol blend testing will need to consider the different engines and
fuel systems currently in service that could be exposed to mid-level
ethanol blends and the long-term impact of using such blends.\244\
After receiving a waiver application, EPA must give public notice and
comment and has 270 days to grant or deny the waiver request.
---------------------------------------------------------------------------
\244\ EPA has expressed what such a waiver testing program might
look like, see Karl Simon, ``Mid Level Ethanol Blend Experimental
Framework: Epa Staff Recommendations,'' June 2008, and Ed Nam
``Vehicle Selection & Sample Size Issues for Catalyst and Evap
Durability Testing,'' November 2008, in the docket (EPA-HQ-OAR-2005-
0161).
---------------------------------------------------------------------------
The Department of Energy (DOE) has developed and initiated a
comprehensive testing program to investigate the potential impacts of
mid-level blends of ethanol. Initial testing was conducted on a limited
number of high-volume vehicles and small non-road engines and a
preliminary report was published in October, 2008.\245\ In addition,
DOE is in the process of leveraging existing EPA vehicle and small
engine test programs (originally designed to test up to 10% ethanol) to
add mid-level ethanol blends to the fuel matrix. DOE's comprehensive
test program is intended to evaluate a wide range of emission,
performance, and durability issues associated with mid-level ethanol
blends (additional reports forthcoming).
---------------------------------------------------------------------------
\245\ Effects of Intermediate Ethanol Blends on Legacy Vehicles
and Small Non-Road Engines, Report 1, Prepared by Oak Ridge National
Laboratory for the Department of Energy, October 2008.
---------------------------------------------------------------------------
DOE is not alone in pursuing mid-level blends. In 2005, the State
of Minnesota, a large producer of corn ethanol, passed a law requiring
that by 2015, 20% of gasoline (by volume) must be replaced by ethanol.
While this level could be achieved with a high percentage of E85 usage
by FFVs, the state has also expressed an interest in moving to 20%
ethanol blends. Several other states and organizations have also
expressed interest in increasing ethanol use by adopting E15 or E20.
The Renewable Fuels Association (RFA) and the American Coalition for
Ethanol (ACE) have been working with various government entities to
investigate the impact of mid-level blends
On March 6, 2009, Growth Energy and 54 ethanol manufacturers
submitted an application for a waiver of the prohibition of the
introduction into commerce of certain fuels and fuel additives set
forth in section 211(f) of the Act. This application seeks a waiver for
ethanol-gasoline blends of up to 15 percent by volume ethanol. The
statute directs the Administrator of EPA to grant or deny this
application within 270 days of receipt by EPA, in this instance
December 1, 2009. EPA recently issued a federal register notice
announcing receipt of the Growth Energy waiver application and
soliciting comment on all aspects of it. Refer to 74 FR 18228 (April
21, 2009).
While the current Growth Energy waiver application is still under
review, as a sensitivity, we considered the implications that adding
E15 or E20 to the marketplace could have on ethanol usage and the
supporting fuel infrastructure should such blends be permitted. For
each case, we assumed that E10 would need to continue to remain in
existence to meet the demand of legacy vehicle and non-road engine
owners. This would also provide consumer choice. Experience in past
fuel programs has shown that many consumers will not be comfortable
refueling on higher ethanol blends and will blame any problems that may
occur on the new fuel (regardless of the actual cause of the vehicle
problems) causing a backlash against the new fuel requirements.
Therefore, we believe it is critical to continue to allow consumers the
choice between mid-level ethanol blends and conventional gasoline
(assumed to be E10 in the future).
For our optimistic mid-level ethanol blends scenario, we assumed
that E15 or E20 could be available at all retail stations nationwide by
the time the nation hits the E10 blend wall, or around 2013. This
assumes a number of actions are taken to bring mid-level blends to
market (explained in more detail below).\246\ We assumed that E10 would
be marketed as premium-grade gasoline, the mid-level ethanol blend (E15
or E20) would serve as regular, and like today, midgrade would be
blended from the two fuels. Those vehicles and equipment which are
unable to refuel on mid-level ethanol blends (or choose not to) could
continue to fill up on E10. This mid-level ethanol blends scenario,
described in more detail in Section 1.7.1.3 of the DRIA, concluded that
if mid-level ethanol blends were to be distributed at all retail
stations nationwide, they could help increase ethanol usage to over 19
billion gallons (with E15) and 25 billion gallons (with E20).
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\246\ Results for other cases are discussed in Section 1.7.1.3
of the DRIA.
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[[Page 25015]]
[GRAPHIC] [TIFF OMITTED] TP26MY09.007
As shown in Figure V.D.2-2, in this optimistic phase-in scenario,
adding E15 could postpone the blend wall by about three years to 2016
and adding E20 could postpone it another three years to 2019. Although
mid-level ethanol blends will fall short of meeting the RFS2
requirements, they could provide interim relief while the county ramps
up E85/FFV infrastructure and/or finds other non-ethanol alternatives
(e.g., cellulosic diesel or biobutanol) to reach the RFS2 volumes.
Our nation's whole system of gasoline fuel regulation, fuel
production, fuel distribution, and fuel use is built around gasoline
with ethanol concentrations limited to E10. As a result, while a waiver
may legalize the use of mid-level ethanol blends under the CAA, there
are a number of other actions that would have to occur to bring mid-
level blends to retail. The time needed to take these actions could
delay the penetration of mid-level ethanol blends into the market. The
CAA only provides a 1 pound RVP waiver for ethanol blends of 10 volume
percent or less. Lacking such an RVP waiver, a special low-RVP gasoline
blendstock would be needed at terminals to allow the formulation of
mid-level ethanol blends that are complaint with EPA RVP requirements.
Providing such a separate gasoline blendstock would present significant
logistical challenges and costs to the fuel distribution system.\247\ A
number of changes would be needed to EPA regulations including those
pertaining to reformulated gasoline, anti-dumping, and gasoline deposit
control additives to accommodate and mid-level ethanol blends. Such
changes would need to be made through the notice and comment process
similar to today's action. In addition, most states require that fuel
comply with the applicable ASTM International (formally known as the
American Standards for Testing and Materials) specification. The
development of an ASTM International specification for mid-level
ethanol blends through an industry consensus process is currently being
initiated.
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\247\ It may be possible for refiners to formulate a gasoline
blendstock that would be suitable for manufacturing mid-level
ethanol blends and E10 at the terminal. While this would avoid the
logistical problems associated with maintaining separate
blendstocks, there could be significant additional refining costs.
---------------------------------------------------------------------------
There are a number of requirements regarding the fire and leak
protection safety of retail fuel dispensing and storage equipment. The
Occupational Safety and Health Administration (OSHA) requires that
retail fuel handling equipment be listed with an independent standards
body such as Underwriters Laboratories (UL). No independent standards
body has listed fuel handling equipment for mid-level ethanol blends.
Furthermore, UL has stated that it would not expand listings for in-use
fuel retail equipment originally listed for E10 blends to cover greater
than E10 blends.\248\ EPA's Office of Underground Storage Tanks (OUST)
requires that UST systems must be compatible with the fuel stored in
the system. These requirements pertain to all components of the system
including the storage tank, connecting piping, pumps, seals and leak
detection equipment.
---------------------------------------------------------------------------
\248\ UL stated that they have data which indicates that the use
of fuel dispensers certified for up to E10 blends to dispense blends
up to a maximum ethanol content of 15 volume percent would not
result in critical safety concerns (http://www.ul.com/newsroom/newsrel/nr021909.html). Based on this, UL stated that it would
support authorities having jurisdiction who decide to permit legacy
equipment originally certified for up to E10 blends to be used to
dispense up to 15 volume percent ethanol. The UL announcement did
address the compatibility of underground storage tank systems with
greater than E10 blends.
---------------------------------------------------------------------------
States typically adopt fire safety codes from either the National
Fire Protection Association (NFPA) or the International Code Council
(ICC). These organizations currently do not have provisions that would
allow the mid-level ethanol blends to be stored/dispensed from existing
equipment at retail. Local safety officials (e.g. fire marshals)
referred to as ``Authorities Having Jurisdiction'' (AHJ's) often
require a UL certification for fuel retail storage/dispensing equipment
although some will accept
[[Page 25016]]
other substantiation of equipment safety such as a manufacture
certification. Fuel retailers must also satisfy the requirements of the
insurance company that they are insured through which may be more
stringent than the legal requirements. Given the liability concerns
associated with leaks from underground storage tanks, these issues have
to be resolved in order to facilitate the widespread use of mid-level
ethanol blends.
The Department of Energy and EPA are currently working with
industry to evaluate what changes may be necessary to underground
storage tank systems, fuel dispensers, and refueling vapor recovery
equipment at fuel retail facilities to handle a mid-level ethanol
blend. If existing equipment proves tolerant to a mid-level ethanol
blend, this could substantially facilitate its introduction at retail.
If the data supports the suitability of legacy retail equipment to
store/dispense a mid-level blend, then the process of seeking
acceptance by the standard bodies discussed above could commence. The
normal processes used by these standards bodies can be lengthy. For
example, the NFPA has a 3 year cycle for evaluating changes to its
codes with proposals for the current cycle due this June. Thus, apart
from the need to technically evaluate the suitability of legacy retail
equipment to handle a mid-level ethanol blend, the need to secure
recognition from standards bodies could delay the introduction of a
mid-level ethanol blend at retail should a waiver be granted by EPA.
If some components of the above-ground existing retail hardware are
found to be incompatible with a mid-level ethanol blend, it may be
possible for them to be replaced through normal attrition. For example
the ``hanging hardware'' which includes the nozzle and hose from the
dispenser is typically replaced every 3 to 5 years. It is also possible
that only minor changes might be needed to equipment that has a longer
service life which might be accomplished without too much difficulty/
cost. However, if extensive new equipment is needed and particularly if
this involves the breaking of concrete, we believe that it is unlikely
that fuel retailer would opt to install equipment specifically for a
mid-level ethanol blend given the projected future need for retail
equipment capable of handling E85.\249\
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\249\ As discussed previously, significant penetration of E85 is
projected to be needed to facilitate the use of the volumes of
ethanol we project would be needed to satisfy the requirements of
the EISA.
---------------------------------------------------------------------------
Finally, all vehicles and nonroad equipment currently in use are
only warranted for ethanol levels not exceeding E10 (except for FFVs),
and the owner's manuals are written to reflect this. Before widespread
acceptance of mid-level ethanol blends by consumers can occur, these
warranty issues would need to be addressed.
c. Partial Waiver for Mid-Level Blends
CAA section 211(f)(4), the waiver provision, states that the
Administrator may grant a fuel waiver if a fuel manufacturer can
demonstrate that the fuel ``will not cause or contribute to a failure
of any emission control device or system (over the useful life of the
motor vehicle, motor vehicle engine, nonroad engine or nonroad vehicle
in which such device or system is used) to achieve compliance by the
vehicle or engine with the emission standards with respect to which it
has been certified.'' For reasons discussed below, it may be possible
that these criteria for a mid-level blend waiver may be met for a
subset of gasoline vehicles or engines but not for all gasoline
vehicles or engines. The waiver criteria are applied over the useful
life of ``the motor vehicle, motor vehicle engine, nonroad engine or
nonroad vehicle in which such device or system is used.'' Assuming the
criteria is met for a certain subset of vehicles, and that adequate
measures could be put in place to ensure that a waiver fuel were only
used in that subset of vehicles or engines, one interpretation of this
provision is that the waiver could apply only to that subset of
vehicles or engines.
One potential outcome from a review of the entire body of
scientific and technical information available may be an indication
that mid-level ethanol blends could meet the criteria of a section
211(f)(4) waiver for some vehicles and engines but not for others. It
may be that certain vehicles and engines operate as intended using mid-
level blends but others may be more susceptible to emissions increases
or durability problems. For example, vehicles or engines without newer
technology that do not readily adjust for the higher oxygen level in
the fuel may experience problems, while newer technology vehicles such
as those meeting our Tier 2 standards may be able to adjust for such
changes as a result of more advanced emissions and fuel control
equipment. Nonroad engines, which are typically small, are likely to be
most susceptible given the less sophisticated technology associated
with such engines. Given this potential outcome, EPA requests comment
on all aspects, both legal and technical, as to the possibility that a
section 211(f)(4) waiver might be granted, in a partial way with
conditions, such that the use of mid-level blends would be restricted
to a subset of the gasoline vehicles or engines covered by the waiver
provision, while those nonroad engines and vehicles not covered by the
waiver would continue using fuels with blends no greater than E10.
Any waiver approval, either fully or partially, is likely to elicit
a market response to add E15 blends to E10 and E0 blends in the
marketplace, rather than replace them. Thus consumers would merely have
an additional choice of fuel.
Experience in past fuel programs has shown that even with consumer
education and fuel implementation efforts, there sometimes continues to
be public concern for new fuel requirements. Several examples include
the phasedown of the amount of lead allowed in gasoline in the 1980s
and the introduction of reformulated gasoline (RFG) in 1995. Some
segments of the public were convinced that the new fuels caused vehicle
problems or decreases in fuel economy. Although substantial test data
proved otherwise, these concerns lingered in some cases for several
years. As a direct result of these experiences, EPA wants to be assured
that prior to potentially granting a waiver for mid-level blends,
sufficient testing has been conducted to demonstrate the compatibility
of a waiver fuel with engine, fuel and emission control system
components.
EPA has previously granted waivers with certain restrictions or
conditions. Among other things, these restrictions have included
requiring fuels to meet certain voluntary consensus-based gasoline
standards such as those developed by the American Society of Testing
and Materials (ASTM standards), requirements that precautions be taken
to prevent using the waiver fuel as a base fuel for adding oxygenates,
and that certain corrosion inhibitors be utilized when producing the
waived fuel.\250\ However, in those waivers, the conditions placed upon
the fuel manufacturer were directly related to manufacturing the fuel
itself. Here, the conditions placed upon the fuel manufacturer would be
on the use of the fuel in certain vehicles or engines. In other words,
the fuel manufacturer would have to ensure that the mid-level blend was
only used in that particular subset of vehicles or engines to be able
to legally manufacture and sell the fuel
[[Page 25017]]
under the terms of the waiver. Since it would become the fuel
manufacturer's responsibility to prevent misfueling, the following
discussion highlights some of the ideas that the fuel manufacturer
could implement, based on particular subsets of vehicles,\251\ to
prevent misfueling.
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\250\ See, for example, 53 FR 3636, February 8, 1988, and 53 FR
33846, September 1, 1988.
\251\ Although it is not possible at this time to know the
contours of a partial waiver with conditions, or even if one might
be appropriate, the remainder of this discussion will refer only to
vehicles covered by the waiver (and not engines) since newer
vehicles are more likely to have more sophisticated emissions and
fuel control equipment, while certain engines might be more affected
for the reasons stated above.
---------------------------------------------------------------------------
If a partial waiver covered only newly manufactured vehicles,
methods focused on the manufacturing of the vehicle could be utilized
to inform the buyer that the vehicle was capable of operating on the
waiver fuel. In this case, approaches such as the use of vehicle
fueling inlet labels and owner's manuals could be utilized in tandem
with retail station fuel dispenser labels. Such an approach depends on
the attention of the vehicle operator to ensure compliance with the
waiver. Additionally, retail station attendants could be trained to
provide guidance to operators on which vehicles are covered under the
waiver.
If only vehicles of certain model years were covered, owners would
know if they could utilize the mid-level blends simply by knowing the
model year (again, in tandem with pump labeling). Alternatively, if
some portion of the existing fleet, not based upon model-year (such as
vehicles meeting EPA Tier 2 emission standards), would also be covered,
the approach would have to include some means by which the operator of
such a vehicle would be made aware that the vehicle being fueled was
covered or not covered by the waiver. Such an approach would likely
involve notification of owners of covered vehicles, through direct
contact or education campaigns, and would likely require the assistance
of the vehicle manufacturers. This approach, as with other approaches,
would require pump labeling.
Other approaches may bring about tighter control of misfueling
situations but may present additional challenges. For example, one
approach might be to provide owners of covered vehicles with a
transaction card similar to a credit card that could be swiped at the
dispenser to allow for the dispensing of a waived mid-level blend.
Presumably, software and/or hardware at dispensing pumps may be able to
be adjusted to accommodate such an approach. Some retail station chains
have already utilized transponder mechanisms to record sales. Similar
transponder systems could be utilized in place of transaction cards.
The above discussion is not meant to be an exhaustive list of
possible approaches for ensuring compliance with a partial waiver, nor
does it explore all the facets of any single approach. EPA recognizes
that there may be legal and practical limitations on what a fuel
manufacturer may be able to do to ensure compliance with the conditions
of the partial waiver. EPA has not previously imposed this type of
``downstream'' condition on the fuel manufacturer as part of a section
211(f)(4) waiver. EPA does, however, have experience with compliance
problems occurring when two types of gasoline have been available at
service stations. Beginning in the mid-1970s with the introduction of
unleaded gasoline and continuing into the 1980s as leaded gasoline was
phased out, there was significant intentional misfueling by consumers.
At the time most service stations had pumps dispensing both leaded and
unleaded gasoline and a price differential as small as a few cents per
gallon was enough to cause some consumers to misfuel. Higher price
differentials could occur if, as expected, mid-level ethanol blends
were to be marketed as the regular grade and E0 or E10 as the premium
grade. The Agency seeks comment regarding whether this is a reasonable
or practical condition for this type of waiver. EPA acknowledges that
the issue of misfueling would be challenging in a situation where a
partial waiver is granted. Therefore, EPA solicits comments on what
measures a fuel manufacturer, EPA or others in the gasoline
distribution network could take for ensuring compliance with a partial
waiver.
While EPA has not analyzed the specific cost of a conditional
waiver, such a waiver would likely carry a cost similar to the costs
described above in Section V.D.3.b. Because existing equipment in
retail stations is certified by Underwriters Laboratories only up to
ten percent ethanol, existing equipment would need to be evaluated for
its acceptability for use with mid-level blends (and deemed to be
acceptable if possible) or it would have to be modified/replaced before
any ethanol blend greater than ten percent could be effectuated in the
marketplace.\252\ If existing retail equipment is found not to be
acceptable for storing/dispensing mid-level blends, the aforementioned
infrastructure challenges would be present and additional costs would
be associated with measures adopted for the prevention of releases due
to material incompatibility, as well as those associated with
misfueling. EPA therefore seeks comment on the compatibility of the
existing retail fuel storage/dispensing equipment with mid-level
ethanol blends. Further, adoption of such a waiver would mean that
fewer vehicles/engines would be able to utilize mid-level blends and,
therefore, the full impact of mid-level blends on the E10 blend wall
under such a scenario would not be as significant as full unrestricted
utilization of such blends.
---------------------------------------------------------------------------
\252\ See previous discussion in Section V.D.3.b of this
preamble regarding the issues that would need to be addressed to
facilitate the introduction of mid-level ethanol blends at retail.
---------------------------------------------------------------------------
d. Non-Ethanol Cellulosic Biofuel Production
While our analysis describes possible pathways by which the market
could meet the RFS2 requirements with 34 billion gallons of ethanol as
E10 and E85, our analysis of the required FFV and E85 infrastructure
growth as well as the required changes to the E10/E85 price
relationship suggests some inherent challenges. Furthermore, we
conclude that the introduction of mid-level ethanol blends (contingent
upon waiver approval) would by itself not allow the country to achieve
the RFS2 standards. Another means of achieving the RFS2 volume
requirements would be through the introduction of non-ethanol
cellulosic biofuels. The growing spread in gasoline and diesel pricing
implies that we are currently moving in the direction of being
oversupplied with gasoline and undersupplied with diesel.\253\ As such,
it makes sense that the market might preferentially investigate diesel
fuel replacements, e.g., cellulosic diesel via Fischer-Tropsch
synthesis, pyrolysis, or catalytic depolymerization. These fuels would
meet the definition of cellulosic biofuel (as well as advanced biofuel)
under the proposed RFS2 program and help reduce the ethanol blend wall
impacts associated with this rule. Although for our analysis we assumed
that the cellulosic biofuel standard would be met with ethanol, the
market could choose a significant volume of other non-ethanol renewable
fuels. DOE and other agencies are currently providing grants to support
critical
[[Page 25018]]
research into these second-generation cellulosic feedstock conversion
technologies. DOE is also providing loan guarantees to help with the
commercialization of such technologies. For more information on non-
ethanol cellulosic biofuels, refer to Section V.A. or Section 1.4.3 of
the DRIA.
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\253\ According to EIA, gasoline and diesel prices were pretty
similar on average for a decade from 1995-2004. However, over the
past four years, diesel prices have begun to track consistently
higher than gasoline prices. To date in 2008, diesel has been priced
more than $0.50/gallon higher than gasoline on average. Source:
http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp.
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e. Measurement Tolerance For E10
Some stakeholders have suggested that the implementation of a
tolerance in the measurement of the ethanol content of gasoline could
allow more ethanol to be used in existing vehicles without the need for
a formal waiver and without the need for more FFVs. Such a tolerance
could allow ethanol contents slightly higher than 10 volume percent
while still treating such blends as meeting the 10 volume percent
limitation on the ethanol content of gasoline.
Although there is no explicit written precedent for permitting
ethanol contents higher than 10 vol%, some have speculated that current
vehicles would not exhibit any noticeable change in performance,
durability, or emissions if a small measurement tolerance for ethanol
content of gasoline were allowed. The current specified test method for
oxygen content ASTM D-5599-00 includes estimates of the measurement
reproducibility that could be used to inform the determination of an
appropriate tolerance for ethanol content in gasoline. For instance,
based on the provided reproducibility, a measurement as high as 11 vol%
ethanol in gasoline might be possible for gasoline that was blended to
meet a 10 vol% ethanol requirement. Historically, however, EPA has
always enforced the 10 vol% waiver at the 10 vol% level without any
tolerance.
The 1978 gasohol waiver application requested a blend of 90%
unleaded gasoline and 10% anhydrous ethanol. Although not specified in
the application, the convention and the practical approach for blending
ethanol into gasoline in 1978 was by volume, and it has continued to be
by volume. Thus, the limit on ethanol in gasoline under the waiver is
10% by volume. This is approximately 3.5% oxygen by weight. The waiver
request did not apply to a level of ethanol in gasoline beyond 10%, and
since the application was approved by default after 180 days due to the
fact that the Administrator did not make an explicit decision in this
timeframe, there is no formal approval that could have indicated what
measurement tolerances might have been acceptable. Thus it has
historically been enforced at the 10 vol% limit without any enforcement
tolerance. However, parties who have raised this option have suggested
that the Agency's previous treatment of the oxygenate content of
gasoline may provide a precedent that would allow for a higher
measurement tolerance for ethanol content.
Prior to and after 1981, several waivers issued by the Agency
allowed the use of various alcohols and ethers in unleaded gasoline. In
1981, the ``substantially similar'' interpretive rule for unleaded
gasoline allowed certain alcohols and ethers at up to 2.0% oxygen by
weight. In 1991 the limit was increased to 2.7% oxygen by weight. For
each of these waivers, the unleaded gasoline base to which the
oxygenate was to be added was to be initially free of oxygenate. With
the exception of ethanol, oxygenates, mostly MTBE, were blended at the
refinery, with the refiner in control of the gasoline used for
blending. This enabled the refiner to ensure that it was free of
oxygenate prior to blending. Ethanol was primarily blended at
terminals. In order to ensure that gasoline blended with ethanol at the
terminal was free of other oxygenates, the ethanol blender first had to
check for the presence of other oxygenates in the base gasoline. In the
mid-1980's ethanol blenders informed EPA that they were having
difficulty finding oxygenate-free gasoline. Much of gasoline had at
least trace amounts of MTBE due to commingling of gasolines with
different oxygenates in the fungible pipeline system. In order to
continue to allow the blending of ethanol up to the 10 vol% limit, EPA
issued a letter stating that it would not consider it to be a violation
of the ethanol sub-sim waiver if up to 10% by volume ethanol were added
to unleaded gasoline containing no more than 2% by volume MTBE.
However, the MTBE must have been present only as a result of
commingling during storage or transport and not purposefully added as
an additional component to the ethanol blend.
Subsequently, two other statements by EPA provided guidance on the
allowable oxygen content of oxygenated fuels. For instance, in a
memorandum dated October 5, 1992, EPA provided interim guidance for
states that allowed averaging programs.\254\ This guidance allowed the
oxygen content of ethanol to be as high as 3.8% by weight, but did not
indicate that the ethanol concentration could be higher than 10 vol%.
Also, in a 1995 RFG/Anti-dumping Q&A it was noted that the maximum
oxygen range for the simple and complex models was 4.0% by weight. This
range was implemented to once again continue to allow the blending of
ethanol up to the 10 vol% limit in cases where an extremely low
gasoline density might increase the calculated weight percent oxygen
content for E10 above the more typical 3.5-3.7 wt% range.
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\254\ Memorandum from Mary T. Smith, Director of the Field
Operations and Support Division, to State/Local Oxygenated Fuels
Contacts, October 5, 1992. Subject: ``Testing Tolerance''.
---------------------------------------------------------------------------
Although we acknowledge that the currently specified test method
ASTM D-5599-00 includes some variability, ethanol is different than
many other fuel properties and components that are controlled in other
fuel programs in one important respect. Fuel properties such as RVP,
and components such as sulfur and benzene, are natural characteristics
of gasoline as a result of the chemical nature of crude oil and the
refining process. Their level or concentration in gasoline is unknown
until measured, and then is dependent upon accuracy of the test method.
In contrast, ethanol is intentionally added in known amounts using
equipment designed to ensure a specific concentration within a small
fraction of one percent. Parties that blend ethanol into gasoline
therefore have precise control over the final concentration. Thus, a
measurement tolerance for ethanol would be less appropriate than
measurement tolerances for other fuel properties and components.
We request comment on whether a measurement tolerance should be
allowed for the ethanol content of gasoline, the basis for such a
tolerance, and what tolerance if any would be appropriate. We also
request comment on whether such a tolerance would fit within the
existing Underwriters Laboratories, Inc. (UL) approval for the safety
of equipment at refueling stations, including underground storage
tanks, pumps, piping, seals, etc.
f. Redefining ``Substantially Similar'' to Allow Mid-Level Ethanol
Blends
Section 211(f)(1) prohibits the introduction into commerce, or
increase in the concentration in use of, gasoline or gasoline additives
for use in motor vehicles unless they are substantially similar to the
gasoline or gasoline additives used in the certification of new motor
vehicles or motor vehicle engines. EPA may grant a waiver of this
prohibition under section 211(f)(4) of the Clean Air Act provided that
the fuel or fuel additive ``will not cause or contribute to a failure
of any emission control device or system (over the useful life of the
motor vehicle, motor vehicle engine, nonroad engine or nonroad vehicle
in which the device or system
[[Page 25019]]
is used) to achieve compliance by the vehicle or engine with the
emission standards to which it has been certified.''
EPA first interpreted the term ``substantially similar'' for
unleaded gasoline and its additives in 1978.\255\ Recognizing that this
interpretation was too limited, EPA updated it in 1980, and again in
1981.\256\ EPA set the limits contained in the interpretation based on
the physical and chemical similarities of the fuel or fuel additives to
those used in the motor vehicle certification process. EPA also
considered information available regarding the emission effects that
such fuels and additives would exhibit relative to the emissions
performance of the certification fuels and fuel additives. The 1981
interpretative rule identified the characteristics and specifications
that EPA determined would make a fuel or fuel additive ``substantially
similar'' to those used in certification. Under this rule, a fuel or
fuel additive would be considered substantially similar if it satisfied
certain limits on fuel and fuel additive composition, did not exceed a
maximum allowable oxygen content of fuel at 2.0% by weight, and met
certain ASTM specifications. Comments on this interpretative rule
requested that EPA increase the maximum oxygen concentration up to 3.5%
oxygen by weight, but EPA rejected this recommendation, stating that it
would keep the limit at 2.0% because of concerns over emissions,
material compatibility, and drivability from use of various alcohols at
higher oxygen contents.
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\255\ 43 FR 11258 (March 17, 1978), 43 FR 24131 (June 2, 1978).
\256\ 45 FR 67443 (October 10, 1980), 46 FR 38582 (July 28,
1981).
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In 1991, EPA amended the interpretive rule by revising the oxygen
content criteria to allow fuels containing aliphatic ethers and/or
alcohols (excluding methanol) to contain up to 2.7% by weight
oxygen.\257\ EPA based this increase in the oxygen content on its
review of information on a wide variety of alcohol and ether blends,
leading it to determine that ``unleaded gasolines with such oxygen
content are chemically and physically substantially similar to, and
have been shown to have emissions properties substantially similar to,
unleaded gasolines used in light-duty vehicle certification.'' \258\
Finally, in 2008, EPA amended the interpretive rule to allow
flexibility for the vapor/liquid ratio specification for fuel
introduced into commerce in the state of Alaska to improve cold
starting for vehicles during the winter months in Alaska.\259\ Thus the
``substantially similar'' interpretive rule for unleaded gasoline
presently allows oxygen content up to 2.7% by weight for certain ethers
and alcohols.
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\257\ 56 FR 5352 (February 11, 1991).
\258\ 56 FR at 5353.
\259\ 73 FR 22277 (April 25, 2008).
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A waiver of the substantially similar prohibition was provided by
operation of law in 1979 under CAA section 211(f)(4), allowing a
gasoline-alcohol fuel blend with up to 10% ethanol by volume (E10)
(``E10 Waiver''). E10 has an oxygen content which typically ranges
between 3.5 and 3.7% by weight, depending on the specific gravity of
the gasoline. Any ethanol blends with greater than 10% ethanol by
volume would have an oxygen content which exceeds the 2.7% by weight
allowed under the current interpretation of ``substantially similar.''
Therefore, under the 1991 interpretive rule, mid-level ethanol blends
would not be considered substantially similar and would require a CAA
section 211(f)(4) waiver.
It has been suggested to EPA that we should update the interpretive
rule such that mid-level ethanol blends would be considered
substantially similar. As in the past, this would involve consideration
of the physical and chemical similarities of such mid-level blends to
fuels used in the certification process, as well as information about
the expected emissions effects of such mid-level blends.\260\ EPA
invites comment on whether mid-level blends of ethanol are physically
and chemically similar enough to the fuels used in the motor vehicle
certification process such that they could be considered
``substantially similar'' to the certification fuels used by EPA. With
respect to the emissions effects of mid-level blends on emissions
performance, EPA recognizes that there may be different impacts
depending on the kind of motor vehicle involved. For example, it has
been suggested that older technology motor vehicles and engines may
have emissions and durability impacts from ethanol blends higher than
10 percent, while Tier 2 and later technology vehicles--2004 and later
model year vehicles--may have fewer such impacts.\261\ These more
recent technology vehicles represent an ever growing proportion of the
in-use fleet. DOE is currently conducting various test programs to
ascertain the impacts of higher level ethanol blends on vehicles and
equipment.
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\260\ One point to be clear on is that the substantially similar
provision relates to fuels used in certification. It is not an issue
of whether mid-level blends are substantially similar to a fuel that
has received a waiver of this prohibition. See 46 FR 38582, 38583
(July 28, 1981). The fuels used in certification include the test
fuels used for exhaust testing, test fuels for evaporative emissions
testing, and the fuels used in the durability process.
\261\ It has also been suggested that nonroad engines and
equipment may experience greater emissions effects and durability
problems when using mid-level blends.
---------------------------------------------------------------------------
EPA seeks comment on all of the issues involved with reconsidering
its interpretation of the term ``substantially similar'' to include
gasoline blended with ethanol to contain up to 4.5% oxygen by weight.
If EPA revised the substantially similar interpretation in this manner,
gasoline blended with up to 12% ethanol by volume (E12) would be
considered ``substantially similar.'' \262\ Given the possibility,
based upon engineering judgment, of a varying impact of a mid-level
ethanol blends on different technology vehicles, EPA invites comment on
limiting such an interpretation to gasoline intended for use in Tier 2
and later motor vehicles. We estimate that defining E12 as
``substantially similar'' for Tier 2 and later motor vehicles could
delay the saturation of the gasoline market with ethanol for up to a
year, allowing for more comprehensive testing on higher blend levels to
be carried out. However, before EPA could determine whether it was
appropriate to revise the interpretation of ``substantially similar''
for gasoline to include gasoline-alcohol fuels blended with up to 12%
ethanol, information would need to be provided to EPA that would allow
for a robust assessment of the impact of E12 over the full useful life
of Tier 2 and later motor vehicles addressing emissions (both tailpipe
and evaporative emissions), materials compatibility, and drivability.
Furthermore, E12 would still need to fulfill registration requirements
(i.e. speciation and health effects testing found at 40 CFR 79.52 and
40 CFR 79.53).
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\262\ As mentioned earlier, EPA has typically used the oxygen
weight percent convention when interpreting the ``substantially
similar'' provision. A change in the ``substantially similar''
interpretation to allow for up to 4.5% oxygen by weight in the form
of ethanol would essentially accommodate ethanol blends up to 12% by
volume since the vast majority of gasolines blended at 12% by volume
ethanol would not exceed this oxygen weight percent limit.
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EPA also seeks comments on additional regulatory and implementation
issues that would arise as a result of changing the ``substantially
similar'' definition to allow for E12. These issues as identified for
mid-level blends in the discussion in Section V.D.3.b include, but are
not necessarily limited to, the applicability of the 1.0 psi RVP waiver
with regard to 10% ethanol blends found at 40 CFR
[[Page 25020]]
80.27(d), Clean Air Act section 211(h); the accommodation of ethanol
blends in making calculations utilizing the complex model for
reformulated and conventional gasoline at 40 CFR 80.45; and detergent
certification requirements found at 40 CFR 80 (Subpart G). Emissions
speciation and health effects testing is required for oxygenate-
specific blends under 40 CFR 79 (Subpart F). Such testing is currently
underway for 10% ethanol blends but not for ethanol levels higher than
10 percent. Additionally, if E12 was allowed under the ``substantially
similar'' definition, presumably such a blend would have to meet one of
the volatility classes of ASTM D4814-88, which is not now the case with
some blends of 10% ethanol blended under the E10 Waiver. Any change in
the allowable maximum ethanol level in motor fuels will impact these
and, potentially, other motor fuel regulations.
Furthermore, there are also implications beyond EPA's motor fuel
regulations. Existing equipment in retail stations is certified by
Underwriters Laboratories only up to 10% ethanol. Thus, either existing
equipment would need to be recertified for E12 (if possible) or it
would have to be replaced before E12 could be effectuated in the
marketplace. In addition, the substantially similar prohibition applies
to the fuel manufacturer, and if the reinterpretation only applied to
gasoline used with Tier 2 and later motor vehicles, then the
manufacturer of a mid-level blend could not introduce it into commerce
for use with any other motor vehicles. This means that the fuel
distribution system would need to be structured in such a way that the
fuel manufacturer could appropriately ensure that the fuel was only
used in Tier 2 or later motor vehicles. Preventing the misfueling of
mid-level blends into vehicles and engines not specified in the
interpretive rule, and ensuring the availability of fuels for other
vehicles and engines, poses a major problem with reinterpreting
``substantially similar'' to include mid-level blends with a
restriction for use in Tier 2 and later motor vehicles. (For a more
detailed discussion on this issue, see Section V.D.3.c above). We seek
comment on these logistical and regulatory concerns as well.
VI. Impacts of the Program on Greenhouse Gas Emissions
A. Introduction
Lifecycle modeling, often referred to as fuel cycle or well-to-
wheel analysis, assesses the net impacts of a fuel throughout each
stage of its production and use including production/extraction of the
feedstock, feedstock transportation, fuel production, fuel
transportation and distribution, and tailpipe emissions.\263\ This
section describes and seeks comment on the methodology developed by EPA
to determine the lifecycle greenhouse gas (GHG) emissions of biofuels
fuels as required by EISA as well as the petroleum-based transportation
fuels being replaced. While much of the discussion below focuses on
those portions of lifecycle assessment particularly important to
biofuel production, the basic methodology was the same for analyzing
both petroleum-based fuels and biofuels. This methodology was utilized
to determine which biofuels (both domestic and imported) qualify for
the four different GHG reduction thresholds established in EISA. This
threshold assessment compares the lifecycle emissions of a particular
biofuel including its production pathway against the lifecycle
emissions of the petroleum-based fuel it is replacing (e.g., ethanol
replacing gasoline or biodiesel replacing diesel). This section also
seeks comment on the Agency's proposal to utilize the discretion
provided in EISA to adjust these thresholds downward should certain
conditions be met. We also explain how feedstocks and fuel types not
included in our analysis will be addressed and incorporated in the
future. The overall GHG benefits of the RFS program, which are based on
the same methodology presented here, are provided in Section VI.F.
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\263\ In this preamble, we are considering ``lifecycle
analysis'' in the context of estimating GHG emissions, as required
by EISA. More generally, the term ``lifecycle analysis'' or
``assessment'' has been defined as an evaluation of all the
environmental impacts across the range of media/exposure pathways
that are associated with a ``cradle to grave'' view of a product or
set of policies. For more information on this broader context,
please see the 2006 EPA publication ``Life Cycle Assessment:
Principles and Practice (EPA/600/R-06/060).
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As described in detail below, EPA has analyzed the lifecycle GHG
impacts of the range of biofuels currently expected to contribute
significantly to meeting the volume mandates of EISA through 2022. In
these analyses we have used the best science available. Our analysis
relies on peer reviewed models and the best estimate of important
trends in agricultural practices and fuel production technologies as
these may impact our prediction of individual biofuel GHG performance
through 2022. We have identified and highlighted assumptions and model
inputs that particularly influence our assessment and seek comment on
these assumptions, the models we have used and our overall methodology
so as to assure the most robust assessment of lifecycle GHG performance
for the final rule.
EPA believes that compliance with the EISA mandate--determining the
aggregate GHG emissions related to the full fuel lifecycle, including
both direct emissions and significant indirect emissions such as land
use changes--makes it necessary to assess those direct and indirect
impacts that occur not just within the United States and also those
that occur in other countries. This applies to determining the
lifecycle emissions for petroleum-based fuels, to determine the
baseline, as well as the lifecycle emissions for biofuels. For
biofuels, this includes evaluating significant emissions from indirect
land use changes that occur in other countries as a result of the
increased production and importation of biofuels in the U.S. As
detailed below, we have included the GHG emission impacts of
international indirect land use changes. We recognize the significance
of including international land use emissions impact and in our
analysis presentation we have been transparent in breaking out the
various sources of GHG emissions so that the reader can readily see the
impact of including international land use impacts.
In addition to the many technical issues addressed in this
proposal, this section also discusses the emissions decreases and
increases associated with the different parts of the lifecycle
emissions of various biofuels, and the timeframes in which these
emissions changes occur. Determining a single lifecycle value that best
represents this combination of emissions increases and decreases
occurring over time led EPA to consider various alternative ways to
analyze the timeframe of emissions related to biofuel production and
use as well as options for adjusting or discounting these emissions to
determine their net present value. Several variations of time period
and discount rate are discussed. The analytical time horizon and the
choice whether to discount GHG emissions and, if so, at what
appropriate rate can have a significant impact on the final assessment
of the lifecycle GHG emissions impacts of individual biofuels as well
as the overall GHG impacts of these EISA provisions and this rule.
We believe that our lifecycle analysis is based on the best
available science, and recognize that in some aspects it represents a
cutting edge approach to addressing lifecycle GHG emissions. Because of
this, varying degrees of uncertainty are in our analysis. For this
proposal, we conducted a number of
[[Page 25021]]
sensitivity analyses which focus on key parameters and demonstrate how
our assessments might change under alternative assumptions. By focusing
attention on these key parameters, the comments we receive as well as
additional investigation and analysis by EPA will allow narrowing of
uncertainty concerns for the final rule. In addition to this
sensitivity analysis approach, we will also explore options for more
formal uncertainty analyses for the final rule to the extent possible.
Because lifecycle analysis is a new part of the RFS program, in
addition to the formal comment period on the proposed rule, EPA is
making multiple efforts to solicit public and expert feedback on our
proposed approach. As discussed in Section XI, EPA plans to hold a
public workshop during the comment period focused specifically on our
lifecycle analysis to help ensure full understanding of the analyses
conducted, the issues addressed and options that should be considered.
We expect that this workshop will help ensure that we receive the most
thoughtful and useful comments to this proposal and that the best
methodology and assumptions are used for calculating GHG emissions
impacts of fuels for the final rule. Additionally we will conduct peer-
reviews of key components of our analysis. As explained in more detail
in the following sections, EPA is specifically seeking peer review of:
Our use of satellite data to project future land use changes; the land
conversion GHG emissions factors estimated by Winrock; our estimates of
GHG emissions from foreign crop production; methods to account for the
variable timing of GHG emissions; and how models are used together to
provide overall lifecycle GHG estimates.
The regulatory purpose of the lifecycle greenhouse gas emissions
analysis is to determine whether renewable fuels meet the GHG
thresholds for the different categories of renewable fuel.
1. Definition of Lifecycle GHG Emissions
The GHG provisions in EISA are notable for the GHG thresholds
mandated for each category of renewable fuel and also the mandated
lifecycle approach to those thresholds. Renewable fuel must, unless
``grandfathered'' as discussed in Section II.B.3., achieve at least 20%
reduction in lifecycle greenhouse gas emissions compared to the average
lifecycle greenhouse gas emissions for gasoline or diesel sold or
distributed as transportation fuel in 2005. Similarly, biomass-based
diesel and advanced biofuels must achieve a 50% reduction, and
cellulosic biofuels a 60% reduction, unless these thresholds are
adjusted according to the provisions in EISA. To EPA's knowledge, the
GHG reduction thresholds presented in EISA are the first lifecycle GHG
performance requirements included in federal law. These thresholds, in
combination with the renewable fuel volume mandates, are designed to
ensure significant GHG emission reductions from the use of renewable
fuels and encourage the use of GHG-reducing renewable fuels.
The definition of lifecycle greenhouse gas emissions established by
Congress is also critical. Congress specified that:
The term `lifecycle greenhouse gas emissions' means the
aggregate quantity of greenhouse gas emissions (including direct
emissions and significant indirect emissions such as significant
emissions from land use changes), as determined by the
Administrator, related to the full fuel lifecycle, including all
stages of fuel and feedstock production and distribution, from
feedstock generation or extraction through the distribution and
delivery and use of the finished fuel to the ultimate consumer,
where the mass values for all greenhouse gases are adjusted to
account for their relative global warming potential.\264\
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\264\ Clean Air Act Section 211(o)(1).
This definition requires EPA to look broadly at lifecycle analyses
and to develop a methodology that accounts for all the important
factors that may significantly influence this assessment, including the
secondary or indirect impacts of expanded biofuels use. EPA's analysis
described below indicates that the assessment of lifecycle GHG
emissions for biofuels is significantly affected by the secondary
agricultural sector GHG impacts from increased biofuel feedstock
production (e.g., changes in livestock emissions due to changes in
agricultural commodity prices) and also by the international impact of
land use change from increased biofuel feedstock production. Thus,
these factors must be appropriately incorporated into EPA's lifecycle
methodology to properly assess full lifecycle GHG performance of
biofuels in accordance with the EISA definition.
2. History and Evolution of GHG Lifecycle Analysis
Traditionally, the GHG lifecycle analysis of fuels has involved
calculating the emissions associated with each individual stage in the
production and use of the fuel (e.g., growing or extracting the
feedstock, moving the feedstock to the processing plant, processing the
feedstock into fuel, moving the fuel to market, and combusting the
fuel.) EPA used this approach for the lifecycle modeling conducted for
the RFS1 program in 2005. However, it has become increasingly apparent
that this type of first order or attributional lifecycle modeling has
notable shortcomings, especially when evaluating the implications of
biofuel policies.\265\ In fact, the main criticism EPA received in
reaction to our previous RFS1 lifecycle analysis was that we did not
include important secondary, indirect, or consequential impacts of
biofuel production and use.
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\265\ See also, Conceptual and Methodological Issues in
Lifecycle Analysis of Transportation Fuels, Mark A. Delucchi,
Institute of Transportation Studies, University of California,
Davis, 2004, UCD-ITS-RR-04-45 for a description of issues with
traditional lifecycle analysis used to model GHG impacts of biofuels
and biofuel policies.
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Several studies and analyses conducted since the completion of RFS1
have contributed to our understanding of the lifecycle GHG emissions of
biofuel production. These studies, and others, have highlighted the
potential impacts of biofuel production on the agricultural sector and
have specifically identified land use change impacts as an important
consideration when determining GHG impacts of
biofuels.266 267 In the meantime, the dramatic increase in
U.S. production of biofuels has heightened the concern about the
impacts biofuels might have on land use and has increased the
importance of considering these indirect impacts in lifecycle analysis.
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\266\ Fargione, J., J. Hill, D. Tilman, S. Polasky, and P.
Hawthorne. 2008. Land clearing and the biofuel carbon debt. Science
319:1235-1238. See http://www.sciencemag.org/cgi/reprint/319/5867/1235.pdf.
\267\ Searchinger, T., R. Heimlich, R.A. Houghton, F. Dong, A.
Elobeid, J. Fabiosa, S. Tokgoz, D. Hayes, and T.-H. Yu. 2008. Use of
U.S. croplands for biofuels increases greenhouse gases through
emissions from land-use change. Science 319:1238-1240. See http://www.sciencemag.org/cgi/reprint/319/5867/1238.pdf.
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Based on the evolution of lifecycle analysis and the new
requirements of EISA, we have developed a comprehensive methodology for
estimating the lifecycle GHG emissions associated with renewable fuels.
Through dozens of meetings with a wide range of experts and
stakeholders, EPA has shared and sought input on this methodology. We
also have relied on the expertise of the U.S. Department of Agriculture
(USDA) and the Department of Energy (DOE) to help inform many of the
key assumptions and modeling inputs for this analysis. Dialogue with
the State of California and the European Union on their parallel, on-
going efforts in GHG
[[Page 25022]]
lifecycle analysis has also helped inform EPA's methodology. As part of
this discussion, we have identified several of the key drivers
associated with these lifecycle GHG emissions estimates, including
assumptions about international land use change and the timing of GHG
emissions over time. The inputs we have received through these
interactions are reflected throughout this section.
Specifically EPA has worked closely with the California Air
Resources Board (CARB) regarding their development of transportation
fuels lifecycle GHG impacts. California Executive Order S-1-07, the Low
Carbon Fuel Standard (LCFS) (issued on January 18, 2007), calls for a
reduction of at least 10 percent in the carbon intensity of
California's transportation fuels by 2020. CARB has worked to develop
lifecycle GHG impacts of different fuels for this Executive Order
rulemaking. More information about this rulemaking and the lifecycle
analysis conducted by California can be found at http://www.arb.ca.gov/fuels/lcfs/lcfs.htm. EPA will continue to coordinate with California on
this rulemaking and the biofuels lifecycle GHG analysis work.
Because this lifecycle GHG emissions analysis is complex and
requires the use of sophisticated computer models, we have taken
several steps to increase the transparency associated with our
analysis. For example, we have updated the model documentation for the
Forest and Agricultural Sector Optimization Model (FASOM), which is
included in the docket. In addition, we have highlighted key
assumptions in FASOM and the Food and Agricultural Policy Research
Institute (FAPRI) models that impact the results of our analysis.
Finally, this NPRM provides an important opportunity for the Agency to
present our work and to receive input from stakeholders and experts in
this field. We will also continue to refine our analysis between the
proposed and final rules, and we will add or update information to the
docket as it becomes available.
B. Methodology
This section describes EPA's methodology for assessing the
lifecycle GHG emissions associated with each biofuel evaluated as well
as the petroleum-based gasoline and diesel fuel these biofuels would
replace. Whereas lifecycle GHG emission methodologies have been well
studied and established for petroleum-based gasoline and diesel fuel,
much of EPA's work has focused on newly developing lifecycle
methodologies for biofuels. Therefore, much of the following section
describes the biofuels-related methodologies and identifies important
issues for comment. Assessing the complete lifecycle GHG impact for
each individual biofuel mandated by EISA requires that a number of key
methodological issues be addressed--from the choice of a baseline to
the selection of the most credible technique for predicting
international land use conversion due to the increase in U.S. renewable
fuels demand, to accounting for the time dimension of changes in GHG
emissions. In this section, we first describe the scenarios we have
analyzed for this proposal. Second, we discuss the scope of our
analysis and what is included in our estimates. Third, we provide
details on the tools and models we used to quantify the GHG emissions
associated with the different fuels. Fourth, we discuss the
uncertainties associated with lifecycle analysis and how we have
addressed them. Fifth, we describe the different components of the
lifecycle that we have analyzed and the key questions we have addressed
in this analysis.
1. Scenario Description
To quantify the lifecycle GHG emissions associated with the
increase in renewable fuel mandated by EISA, we compared the
differences in total GHG emissions between two future scenarios. The
first assumed a ``business as usual'' volume of a particular renewable
fuel based on what would likely be in the fuel pool in 2022 without
EISA, as predicted by the Energy Information Agency's Annual Energy
Outlook (AEO) for 2007 (which took into account the economic and policy
factors in existence in 2007 before EISA). The second assumed the
higher volume of renewable fuels as mandated by EISA for 2022. For each
individual biofuel, we analyzed the incremental GHG emission impacts of
increasing the volume of that fuel to the total mix of biofuels needed
to meet the EISA requirements. Rather than focus on the impacts
associated with a specific gallon of fuel and tracking inputs and
outputs across different lifecycle stages, we determined the overall
aggregate impacts across sections of the economy in response to a given
volume change in the amount of biofuel produced.\268\
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\268\ We then normalize those impacts for each gallon of fuel
(or Btu) by dividing total impacts over the given volume change.
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This analysis is not a comparison of biofuel produced today versus
biofuel produced in the future. Instead, it is a comparison of two
future scenarios. Any projected changes in factors such as crop yields,
energy costs, or production plant efficiencies, both domestically and
internationally, are reflected in both scenarios. We focused our
analyses on 2022 results for three reasons. First, it would require an
extremely complex assessment and administratively difficult
implementation program to track how biofuel production might
continuously change from month to month or year to year. Instead, it
seems appropriate that each biofuel be assessed a level of GHG
performance that is constant over the implementation of this rule,
allowing fuel providers to anticipate how these GHG performance
assessments should affect their production plans. Second, it is
appropriate to focus on 2022, the final year of ramp up in the required
volumes of renewable fuel as this year. Assessment in this year allows
the complete fuel volumes specified in EISA to be incorporated. Third,
since the GHG assessment compares performance between a business as
usual case and the mandated volumes case, many of the factors that
change over time such as crop yield per acre are reflected in both
cases. Therefore the differences in these parallel assessments are
unlikely to vary significantly over time.
EPA requests comment on its proposal to adopt fixed assessments of
fuels meeting the GHG thresholds based on a 2022 performance
assessment. Additional information on the scenarios modeled and the
supplemental analyses that will be conducted for the final rule is
included in Chapter 2 of the DRIA.
In the existing Renewable Fuel Standard rules adopted in response
to the Energy Policy Act of 2005, biofuels and RINs associated with
them are not based on regional differences of where the feedstock was
grown or the biofuel was produced. In effect, the RINs apply to a
national average of the fuel type. Similarly, this proposal does not
distinguish biofuel on the basis of where within the country the
biofuel feedstock was grown or the biofuel produced. Thus, for example,
ethanol produced from corn starch using the same production technology
will receive the same GHG lifecycle assessment regardless of where the
corn was grown or at what facility the biofuel was produced. There are
regional differences in soil types, weather conditions, and other
factors which could affect, for example, the amount of fertilizer
applied and thus the GHG impact of corn production. Such factors could
vary somewhat across a region, within a state and even within a county.
The agricultural models used to conduct this analysis do distinguish
crop production
[[Page 25023]]
by region domestically and by country internationally. However, biofuel
feedstocks such as corn or soybean oil are well traded commodities
including internationally. So, for example, if corn in a certain
location in Iowa is used to produce ethanol, corn from all other
regions will be used to replace that corn for all its other potential
uses. Therefore, it is not appropriate to ascribe the indirect affects,
both domestically and internationally, to corn grown in one area
differently to corn (or other biofuel feedstock) grown in another area.
Our national treatment of biofuel feedstock also pertains to fuels
produced in other countries. Thus for example, sugarcane-based ethanol
produced in Brazil is all treated the same regardless of where the
sugarcane was grown in Brazil. Nevertheless, comments are invited on
the option of differentiating biofuels in the future based on the
location of their feedstock production within a country.
2. Scope of the Analysis
a. Legal Interpretation of Lifecycle Greenhouse Gas Emissions
As described in VI.A.1, the definition of lifecycle greenhouse gas
emissions refers to the ``aggregate quantity of GHG emissions'' that
are ``related to the full fuel lifecycle.'' The fuel lifecycle includes
``all stages of fuel and feedstock production and distribution, from
feedstock generation or extraction through * * * use of the finished
fuel to the ultimate consumer.'' The aggregate quantity of GHG
emissions includes ``direct emissions'' and ``significant indirect
emissions such as significant emission from land use changes.'' This
provision is written in generally broad and expansive terms, such as
``aggregate quantity'', ``related to'', ``full fuel lifecycle'', and
``all stages'' of production and distribution. At the same time, these
and other terms are not themselves defined and provide discretion to
the Administrator in implementing this definition. For example, the
word ``significant,'' which is used to modify ``indirect emissions,''
is not defined.
The definition includes both ``direct'' and ``significant
indirect'' emissions related to the full fuel lifecycle. We consider
direct emissions as those that are emitted from each stage of the full
fuel lifecycle, and indirect emissions as those from second order
effects that occur as a consequence of the full fuel lifecycle. For
example, direct emissions for a renewable fuel would include those from
the growing of renewable fuel feedstock, the distribution of the
feedstock to the renewable fuel producer, the production of renewable
fuel, the distribution of the finished fuel to the consumer, and the
use of the fuel by the consumer as transportation fuel. Similarly,
direct emissions associated with the baseline fuel would include
extraction of the crude oil, distribution of the crude oil to the
refinery, the production of gasoline and diesel from the crude oil, the
distribution of the finished fuel to the consumer, and the use of the
fuel by the consumer. Indirect emissions would include other emissions
impacts that result from fuel production or use, such as changes in
livestock emissions resulting from changes in livestock numbers, or
shifts in acreage between different crop types. The definition of
indirect emissions specifically includes ``land use changes'' which
would include changes in the kind of usage that land is put to such as
changes in forest, pasture, savannah, and crop use.\269\
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\269\ Arguably shifts in acreage between different crops also
could be considered a land use change, but we believe there will be
less confusion if the term land use change is used with respect to
changes in land such as changing from savannah or forest to
cropland. There is no difference in result, as in both cases the
emissions need to be significant.
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In considering how to address land use changes in our lifecycle
analysis, two distinct questions have been raised--whether to account
for emissions that occur outside of the U.S., and under what
circumstances land use change should properly be included in the
lifecycle analysis.
On the question of considering GHG emissions that occur outside of
the U.S., it is important to be clear that including such emissions in
the lifecycle analysis does not exercise regulatory authority over
activities that occur solely outside the U.S., and does not raise
questions of extra-territorial jurisdiction. EPA's regulatory action
involves classification of products either produced in the U.S. or
imported into the U.S. EPA is simply assessing whether the use of these
products in the U.S. satisfies requirements under the Clean Air Act for
the use of designated volumes of renewable fuel, cellulosic biofuel,
biomass-based diesel and advanced biofuel, as those terms are defined
in the Act. Considering international emissions in determining the
lifecycle GHG emissions of the domestically produced or imported fuel
does not change the fact that the actual regulation of the product
involves its use solely inside the U.S.
When looking at the issue of international versus domestic
emissions, it is important to recognize that a large variety of
different activities outside the U.S. play a major part of the full
fuel lifecycle of baseline and renewable fuels. For example, for
baseline fuels (i.e., gasoline and diesel fuels used as transportation
fuel in 2005), GHG emissions associated with extraction and delivery of
crude oil imported to the U.S. all have occurred overseas. In addition,
for imported gasoline or diesel, all of the crude extraction and
delivery emissions, as well as the emissions associated with refining
and distribution of the finished product to the U.S., would have
occurred overseas. For imported renewable fuel all of the emissions
associated with feedstock production and distribution, processing of
the feedstock into renewable fuel, and delivery of the finished
renewable fuel to the U.S. would have occurred overseas. The definition
of lifecycle greenhouse gas emissions makes it clear that EPA is to
determine the aggregate emissions related to the ``full'' fuel
lifecycle, including ``all stages of fuel and feedstock production and
distribution.'' Thus, EPA could not, as a legal matter, ignore those
parts of a fuel lifecycle that occur overseas.
Drawing a distinction between GHG emissions that occur inside the
U.S. as compared to emissions that occur outside the U.S. would
dramatically alter the lifecycle analysis in a way that bears no
apparent relationship to the purpose of this provision. The purpose of
including lifecycle GHG thresholds in this statutory provision is to
require the use of renewable fuels that achieve reductions in GHG
emissions compared to the baseline. Drawing a distinction between
domestic and international emissions would ignore a large part of the
GHG emission associated with the different fuels, and would result in a
GHG analysis of baseline renewable fuels that bears no relationship to
the real world emissions impact of the fuels. The baseline would be
significantly understated, given the large amount of imported crude
used to produce gasoline and diesel, and the importation of finished
gasoline and diesel, in 2005. Likewise, the emissions associated with
imported renewable fuel would be understated, as it would only consider
the emissions from distribution of the fuel to the consumer and the use
of the fuel by the consumer, and would ignore both the emissions that
occurred overseas as well as the emissions reductions from the intake
of CO2 from growing of the feedstock. While large
percentages of GHG emissions would be ignored, this would take place in
a context where the global warming impact of emissions is irrespective
of
[[Page 25024]]
where the emissions occur. Thus taking such an approach would
essentially undermine the provision, and would be an arbitrary
interpretation of the broadly phrased text used by Congress.
While the emissions discussed above would more typically be
considered direct emissions related to the full fuel lifecycle, there
would also be no basis to cover just foreign direct emissions while
excluding foreign indirect emissions. The text of the statute draws no
such distinction, nor is there a distinction in achieving the purposes
of the provision. GHG emissions impact global warming wherever they
occur, and if the purpose is to achieve some reduction in GHG emissions
in order to help address global warming, then ignoring GHG emissions
because they are emitted outside our borders versus inside our borders
interferes with the ability to achieve this objective.
For example, domestic production of a renewable fuel could lead to
indirect emissions, whether from land use changes or otherwise, some
occurring within the U.S. and some occurring in other countries.
Similarly, imported renewable fuel could have resulted in the same
indirect emissions whether occurring in the country that produced the
biofuel or in other countries. It would be arbitrary to assign the
indirect emissions to the domestic renewable fuel but not to assign the
identical indirect emissions that occur overseas to an imported
product.
Based on the above, EPA believes that the definition of lifecycle
greenhouse gas emissions is properly interpreted as including all
direct and significant indirect GHG emissions related to the full fuel
lifecycle, whether or not they occur in the U.S. This applies to both
the baseline lifecycle greenhouse emissions as well as the lifecycle
greenhouse gas emissions for various renewable fuels.
EPA recognizes, as discussed later, our estimates of domestic
indirect emissions are more certain than our estimate of international
indirect emissions. The issue of how to evaluate and weigh the various
elements of the lifecycle analysis, and properly account for
uncertainty in our estimates, is a different issue, however. The issue
here is whether the definition of lifecycle greenhouse gas emissions is
properly interpreted as including direct and significant indirect
emissions that occur outside the U.S. as well as those that occur
inside the U.S.
As to the question of which land use changes should be included in
our lifecycle analyses, a central element to focus on is the
requirement that such indirect emissions be related to the full fuel
lifecycle. The term ``related to'' is generally interpreted as
providing a broad and expansive scope for a provision. It has routinely
been interpreted as meaning to have a connection to or refer to a
matter. To determine whether an indirect emission has the appropriate
connection to the full fuel lifecycle, we must look at both the
objectives of this provision as well as the nature of the relationship.
In this case, EPA has used a global model that projects a variety
of agricultural impacts that stem from the use of feedstocks to produce
renewable fuel. We have estimated shifts in types of crops planted and
increases in crop acres planted. There is a direct relationship between
these shifts in the agricultural market as a consequence of the
increased demand for biofuels in the U.S. Increased U.S. demand for
biofuel feedstocks diverts these feedstocks from other competing uses,
and also increases the price of the feedstock, thus spurring
production. To the extent feedstocks like corn and soybeans are traded
internationally, this combined impact of lower supply from the U.S. and
higher commodity prices encourages international production to fill the
gap. Our analysis uses country specific information to determine the
amount, location, and type of land use change that would occur to meet
this change in production patterns. The linkages are generally close,
and are not extended or overly complex. While there is clearly
significant uncertainty in determining the specific degree of land use
change and the specific impact of those changes, there is considerable
overall certainty as to the existence of the land use changes in
general, the fact that GHG emissions will result, and the cause and
effect linkage of these emissions impacts to the increased use of
feedstock for production of renewable fuels.
Overall, EPA is confident that it is appropriate to consider the
estimated emissions from land use changes as well as the other indirect
emissions as ``related to'' the full fuel lifecycle, based on the
reasonable technical basis provided by the modeling for the connection
between the full fuel lifecycle and the indirect emissions, as well as
for the determination that the emissions are significant. EPA believes
uncertainty in the resulting aggregate GHG estimates should be taken
into consideration, but that it would be inappropriate to exclude
indirect emissions estimates from this analysis. Developing a
reasonable estimate of these kinds of indirect emissions will allow for
a reasoned evaluation of total GHG impacts, which is needed to promote
the objectives of this provision, as compared to ignoring or not
accounting for these indirect emissions.
b. System Boundaries
It is important to establish clear system boundaries in this
analysis. By determining a common set of system boundaries, different
fuel types can then be validly compared. As described in the previous
section, we have assessed the direct and indirect GHG impacts in each
stage of the full fuel lifecycle for biofuels and petroleum fuels.
To capture the direct emissions impacts of feedstock production in
our analysis, we included the agricultural inputs (e.g., the fuel used
in the tractor, the energy used to produce and transport fertilizer to
the field) needed to grow crops directly used in biofuel production. We
also included the N2O emissions associated with agricultural
sector practices used in biofuel production (including direct and
indirect N2O emissions from synthetic fertilizer
application, N fixing crops, crop residue, and manure management), as
well as the land use change associated with converting land to grow
crops directly used in biofuel production. To capture the indirect, or
secondary, GHG emissions that result from biofuel feedstock production,
we relied on the internationally accepted lifecycle assessment
standards developed by the International Organization for
Standardization (ISO). Examples of significant secondary impacts
include the agricultural inputs associated with crops indirectly
impacted by the use of feedstock for biofuel production (domestically
and internationally), the emissions associated with land use change
that are indirectly impacted by using feedstocks for biofuel production
(e.g., to make up for lost U.S. exports), changes in livestock herd
numbers that result from higher feed costs, and changes in rice methane
emissions indirectly impacted by shifts in acres to produce feedstocks
for biofuel production. These indirect or secondary impacts would not
have occurred if it were not for the use of biomass to produce a
biofuel.
We did not include the infrastructure related GHG emissions (e.g.,
the energy needed to manufacture the tractor used on the farm) or the
facility construction-related emissions (e.g., steel or concrete needed
to construct a refinery). As part of the GHG analysis performed for
RFS1, we performed a sensitivity analysis on expanding the corn
production system to include farm equipment production to determine the
impact it has on the overall results of our analysis. We found that
including
[[Page 25025]]
farm equipment production energy use and emissions increases corn
ethanol lifecycle energy use and GHG emissions and decreases the corn
ethanol lifecycle GHG benefit as compared to petroleum gasoline by
approximately 1%. Furthermore, to be consistent in the modeling if
system boundaries are expanded to include production of farming
equipment they should also be expanded to include producing other
material inputs to both the ethanol and petroleum lifecycles. The net
effect of this would be a slight increase in both the ethanol and
petroleum fuel lifecycle results and a smaller or negligible effect on
the comparison of the two.
For this proposal, we have not yet incorporated secondary energy
sector impacts, however we plan to have this analysis complete for the
final rule. Additional details on the system boundaries are included in
the DRIA Chapter 2.
3. Modeling Framework
Currently, no single model can capture all of the complex
interactions associated with estimating lifecycle GHG emissions for
biofuels, taking into account the ``significant indirect emissions such
as significant emissions from land use change'' required by EISA. For
example, some analysis tools used in the past focus on process
modeling--the energy and resultant emissions associated with the direct
production of a fuel at a petroleum refinery or biofuel production
facility. But this is only one component in the production of the fuel.
Clearly in the case of biofuels, impacts from and on the agricultural
sector are important, because this sector produces feedstock for
biofuel production. Commercial agricultural operations make many of
their decisions based on an economic assessment of profit maximization.
Assessment of the interactions throughout the agricultural sector
requires an analysis of the commodity markets using economic models.
However, existing economy wide general equilibrium economic models are
not detailed enough to capture the specific agricultural sector
interactions critical to our analysis (e.g., changes in acres by crop
type) and would not provide the types of outputs needed for a thorough
GHG analysis. As a result, EPA has used different tools that have
different strengths for each specific component of the analysis to
create a more comprehensive estimate of GHG emissions. Where no direct
links between the different models exist, specific components and
outputs of each are used and combined to provide an analytical
framework and the composite lifecycle assessment results. As this is a
new application of these modeling tools, EPA plans to organize peer
review of our modeling approach. The individual models are described in
the following sections and in more detail in Chapter 2 of the DRIA.
To quantify the emissions factors associated with different steps
of the production and use of various fuels (e.g., extraction of
petroleum products, transport of feedstocks), we used the spreadsheet
analysis tool developed by Argonne National Laboratories, the
Greenhouse gases, Regulated Emissions, and Energy use in Transportation
(GREET) model. This analysis tool includes the GHG emissions associated
with the production and combustion of fossil fuels (diesel fuel,
gasoline, natural gas, coal, etc.). These fossil fuels are used both in
the production of biofuels, (e.g., diesel fuel used in farm tractors
and natural gas used at ethanol plants) and could also be displaced by
renewable fuel use in the transportation sector. GREET also estimates
the GHG emissions estimates associated with electricity production
required for biofuel and petroleum fuel production. For the
agricultural sector, we also relied upon GREET to provide GHG emissions
associated with the production and transport of agricultural inputs
such as fertilizer, herbicides, pesticides, etc. While GREET provides
direct GHG emissions estimates associated with the extraction-through-
combustion phases of fuel use, it does not capture some of the
secondary impacts associated with the fuel, such as changes in the
composition of feed used for animal production, which would be expected
due to changes in cost. EPA addresses these secondary impacts through
other models described later in this section. GREET has been under
development for several years and has undergone extensive peer review
through multiple updates. Of the available sources of information on
lifecycle GHG emissions of fossil energy consumed, we believe that
GREET offers the most comprehensive treatment of emissions from the
covered sources.
For some steps in the production of biofuels, we used more detailed
models to capture some of the dynamic market interactions that result
from various policies. Here, we briefly describe the different models
incorporated into our analysis to provide specific details for various
lifecycle components.
To estimate the changes in the domestic agricultural sector (e.g.,
changes in crop acres resulting from increased demand for biofuel
feedstock or changes in the number of livestock due to higher corn
prices) and their associated emissions, we used the FASOM model,
developed by Texas A&M University and others. FASOM is a partial
equilibrium economic model of the U.S. forest and agricultural sectors.
EPA selected the FASOM model for this analysis for several reasons.
FASOM is a comprehensive forestry and agricultural sector model that
tracks over 2,000 production possibilities for field crops, livestock,
and biofuels for private lands in the contiguous United States. It
accounts for changes in CO2, methane, and N2O
from most agricultural activities and tracks carbon sequestration and
carbon losses over time. Another advantage of FASOM is that it captures
the impacts of all crop production, not just biofuel feedstock. Thus,
as compared to some earlier assessments of lifecycle emissions, using
FASOM allows us to determine secondary agricultural sector impacts,
such as crop shifting and reduced demand due to higher prices. It also
captures changes in the livestock market (e.g., smaller herd sizes that
result from higher feed costs) and U.S. export changes. FASOM also has
been used by EPA to consider U.S. forest and agricultural sector GHG
mitigation options.\270\
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\270\ Greenhouse Gas Mitigation Potential in U.S. Forestry and
Agriculture, EPA Document 430-R-05-006. See http://www.epa.gov/sequestration/greenhouse_gas.html.
---------------------------------------------------------------------------
To estimate the impacts of biofuels feedstock production on
international agricultural and livestock production, we used the
integrated FAPRI international models, developed by Iowa State
University and the University of Missouri. These models capture the
biological, technical, and economic relationships among key variables
within a particular commodity and across commodities. FAPRI is a
worldwide agricultural sector economic model that was run by the Center
for Agricultural and Rural Development (CARD) at Iowa State University
on behalf of EPA. The FAPRI models have been previously employed to
examine the impacts of World Trade Organization proposals and changes
in the European Union's Common Agricultural Policy, to analyze farm
bill proposals since 1984, and to evaluate the impact of biofuel
development in the United States. In addition, the FAPRI models have
been used by the USDA Office of Chief Economist, Congress, and the
World Bank to examine agricultural impacts from government policy
changes, market developments, and land use shifts.
Although FASOM predicts land use and export changes in the U.S. due
to
[[Page 25026]]
greater demand for domestic biofuel feedstock, it does not assess how
international agricultural production might respond to these changes in
commodity prices and U.S. exports. The FAPRI model does predict how
much crop land will change in other countries but does not predict what
type of land such as forest or pasture will be affected. We used data
analyses provided by Winrock International to estimate what land types
will be converted into crop land in each country and the GHG emissions
associated with the land conversions. Winrock has used 2001-2004
satellite data to analyze recent land use changes around the world that
have resulted from the social, economic, and political forces that
drive land use. Winrock has then combined the recent land use change
patterns with various estimates of carbon stocks associated with
different types of land at the state level. This international land use
assessment is an important consideration in our lifecycle GHG
assessment and is explained in more detail later in this section.
To test the robustness of the FASOM, FAPRI and Winrock results, we
are also evaluating the Global Trade Analysis Project (GTAP) model, a
multi-region, multi-sector, computable general equilibrium model that
estimates changes in world agricultural production. Maintained through
Purdue University, GTAP projects international land use change based on
the economics of land conversion, rather than using the historical data
approach applied by FAPRI/Winrock. GTAP is designed to project changes
in international land use as a result of the change in U.S. biofuel
policies, based on the relative land use values of cropland, forest,
and pastureland. The GTAP design has the advantage of explicitly
modeling the competition between different land types due to a change
in policy. As further discussed in Section VI.B.5.iv, GTAP has several
disadvantages, some of which prevented its use for the proposal. We
expect to correct several of these shortcomings between the proposed
and final rules and therefore continue to evaluate how the GTAP model
could be used as part of the final rule.
The assessments provided in this proposal use the values provided
by the Intergovernmental Panel on Climate Change (IPCC) to estimate the
impacts of N2O emissions from fertilizer application.
However, due to concern that this may underestimate N2O
emissions from fertilizer application, \271\ we are working with the
CENTURY and DAYCENT models, developed by Colorado State University, to
update our assessments. The DAYCENT model simulates plant-soil systems
and is capable of simulating detailed daily soil water and temperature
dynamics and trace gas fluxes (CH4, N2O,
NOX and N2). The CENTURY model is a generalized
plant-soil ecosystem model that simulates plant production, soil carbon
dynamics, soil nutrient dynamics, and soil water and temperature. We
anticipate the results of this new modeling work will be reflected in
our assessments for the final rule. More description of this ongoing
work is included in the Chapter 2 of the DRIA.
---------------------------------------------------------------------------
\271\ Crutzen, P. J., Mosier, A. R., Smith, K. A., and
Winiwarter, W.: N2O release from agro-biofuel production
negates global warming reduction by replacing fossil fuels, Atmos.
Chem. Phys., 8, 389-395, 2008. See http://www.atmos-chem-phys.net/8/389/2008/acp-8-389-2008.pdf.
---------------------------------------------------------------------------
To estimate the GHG emissions associated with renewable fuel
production, we used detailed ASPEN-based process models developed by
USDA and DOE's National Renewable Energy Laboratory (NREL). While GREET
contains estimates for renewable fuel production, these estimates are
based on existing technology. We expect biofuel production technology
to improve over time, and we projected improvements in process
technology over time based on available information. These projections
are discussed in DRIA Chapter 4. We then utilized the ASPEN-based
process models to assess the impacts of these improvements. We also
cross-checked the ASPEN-based process model predictions by comparing
them to a number of industry sources and other modeling efforts that
estimate potential improvements in ethanol production over time,
including the Biofuel Energy Systems Simulator (BESS) model. BESS is a
software tool developed by the University of Nebraska that calculates
the energy efficiency, greenhouse gas (GHG) emissions, and natural
resource requirements of corn-to-ethanol biofuel production systems. We
used the GREET model to estimate the GHG emissions associated with
current technology as used by petroleum refineries, because we do not
expect significant changes in petroleum refinery technology.
We used the EPA-developed Motor Vehicle Emission Simulator (MOVES)
to estimate vehicle tailpipe GHG emissions. The MOVES modeling system
estimates emissions for on-road and nonroad sources, covers a broad
range of pollutants, and allows multiple scale analysis, from fine-
scale analysis to national inventory estimation.
Finally, for the FRM we intend to use an EPA version of the Energy
Information Administration's National Energy Modeling System (NEMS) to
estimate the secondary impacts on the energy market associated with
increased renewable fuel production. NEMS is a modeling system that
simulates the behavior of energy markets and their interactions with
the U.S. economy by explicitly representing the economic decision-
making involved in the production, conversion, and consumption of
energy products. NEMS can reflect the secondary impacts that greater
renewable fuel use may have on the prices and quantities of other
sources of energy, and the greenhouse gas emissions associated with
these changes in the energy sector. It was not possible to complete
this analysis in time for the NPRM
While EPA is using state-of-the-art tools available today for each
of the lifecycle components considered, using multiple models
necessitates integrating these models and, where possible, applying a
common set of assumptions. As discussed later in this section, this is
particularly important for the two agricultural sector models, FASOM
and FAPRI, which are being used in combination to describe the
agricultural sector impacts domestically and internationally. As
described in more detail in the DRIA Chapter 5, we have worked with the
FAPRI and FASOM models to align key assumptions. As a result, the
projected agricultural impacts described in Section IX are relatively
consistent across both models. One outstanding issue is the differences
between the modeling results associated with increased soybean-based
biodiesel production. We intend to further refine the soybean biodiesel
scenarios for the final rule. Additional details on all of the models
used can be found in DRIA Chapter 2. Finally, as noted earlier, we are
planning to have a number of aspects of our modeling framework peer
reviewed before finalizing these regulations. In the sections below, we
have identified specific peer review plans.
4. Treatment of Uncertainty
While EPA believes the methodology presented here represents a
robust and scientifically credible approach, we recognize that some
calculations of GHG emissions are relatively straight-forward, while
others are not. The direct, domestic emissions are relatively well
known. These estimates are based on well-established process models
that can relatively accurately capture
[[Page 25027]]
emissions impacts. For example, the energy and GHG emissions used by a
natural gas-fired ethanol plant to produce one gallon of ethanol can be
calculated through direct observations, though this will vary somewhat
between individual facilities. The indirect domestic emissions are also
fairly well understood; however, these results are sensitive to a
number of key assumptions (e.g., current and future corn yields). We
address uncertainty in this area by testing the impact of changing
these assumptions on our results. Finally, the indirect, international
emissions are the component of our analysis with the highest level of
uncertainty. For example, identifying what type of land is converted
internationally and the emissions associated with this land conversion
are critical issues that have a large impact on the GHG emissions
estimates. We address this uncertainty by using sensitivity analyses to
test the robustness of the results based on different assumptions. We
also identify areas of additional work that will be completed prior to
the final rulemaking. For example, while we utilized an approach using
comprehensive agricultural sector models and recent satellite data to
determine the emissions resulting from international land use impacts,
we are also considering an alternative methodology (the analyses using
GTAP) that estimates changes in land use based on the relative land use
values of cropland, forest, and pastureland. Additionally, we are
considering country-specific information which may allow us to better
predict specific trends in land use such as the degree to which
marginal or abandoned pasture land will need to be replaced if used
instead for crop production. In addition to the sensitivity analysis
approach, we will also explore options for more formal uncertainty
analyses for the final rule to the extent possible. However, formal
uncertainty analyses generally include an assumption of a statistically
based distribution of likely outcomes. In the time available for
developing this proposal, we have not developed an analytical technique
which allows us to determine the likelihood of a range of possible
outcome across the wide range of critical factors affecting lifecycle
GHG assessment. We specifically ask for recommendations on how best to
conduct a sound, statistically based uncertainty analysis for the final
rule.
Despite the uncertainty associated with international land use
change, we would expect at least some international land use change to
occur as demand for crop land increases as a result of this rule.
Furthermore, the conversion of crop land will lead to GHG emission from
land conversion that must be accounted for in the calculation of
lifecycle GHG emissions. As discussed above, we believe that
uncertainty in the effects and extent of land use changes is not a
sufficient reason for ignoring land use change emissions. Although
uncertainties are associated with these estimates, it would be far less
scientifically credible to ignore the potentially significant effects
of land use change altogether than it is to use the best approach
available to assess these known emissions. We anticipate that comment
and information received in response to this proposal as well as
additional analyses will improve our assessment of land use impacts for
the final rule. Finally, we note that further research on key variables
will result in a more robust assessment of these impacts in the future.
5. Components of the Lifecycle GHG Emissions Analysis
As described previously, GHG emissions from many stages of the full
fuel lifecycle are included within the system boundaries of this
analysis. Details on how these emissions were calculated are included
in the DRIA Section 2. This section highlights the key questions that
we have attempted to address in our analysis. In addition, this section
identifies some of the key assumptions that influence the GHG emissions
estimates in the following section.
a. Feedstock Production
Our analysis addresses the lifecycle GHG emissions from feedstock
production by capturing both the direct and indirect impacts of growing
corn, soybeans, and other renewable fuel feedstocks. For both domestic
and international agricultural feedstock production, we analyzed four
main sources of GHG emissions: agricultural inputs (e.g., fertilizer
and energy use), fertilizer N2O, livestock, and rice
methane. (Emissions related to land use change are discussed in the
next section).
As described in Section IX.A, EPA uses FASOM to model domestic
agricultural sector impacts and uses FAPRI to model international
agricultural sector impacts. However, we also recognize that these
emission estimates rely on a number of key assumptions, including crop
yields, fertilizer application rates, use of distiller grains and other
co-products, and fertilizer N2O emission rates. As described
in the following sections, we have used sensitivity analyses to test
the impact of changing these assumptions on our results.
i. Domestic Agricultural Sector Impacts
Agricultural Sector Inputs: GHG emissions from agricultural sector
inputs (chemical and energy) are determined based on output from FASOM
combined with default factors for GHG emissions from GREET. Fuel use
emissions from GREET include both the upstream emissions associated
with production of the fuel and downstream combustion emissions. Inputs
are based on historic rates by region and include projected increases
to account for yield improvements over time. This yield increase does
not capture changes due to cropping practices such as shifts to corn-
after-corn rotations.
N2O Emissions: FASOM estimates N2O emissions
from fertilizer application and nitrogen fixing crops based on the
amount of fertilizer used and different regional factors to represent
the percent of nitrogen (N) fertilizer applied that result in
N2O emissions. This approach is consistent with IPCC
guidelines for calculating N2O emissions from the
agricultural sector.\272\ A recent paper \273\ raised the question of
whether N2O emissions are significantly higher than
previously estimated. To better understand this issue, we are working
with Colorado State University to analyze N2O emissions.
Specifically, Colorado State University will provide several key
refinements for a re-analysis of land use and cropping trends and GHG
emissions in the FASOM assessment, including:
---------------------------------------------------------------------------
\272\ 2006 Intergovernmental Panel on Climate Change (IPCC)
Guidelines for National Greenhouse Gas Inventories, Volume 4,
Chapter 11, N2O emissions from Managed Soils, and
CO2 Emissions from lime and Urea Application. See http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol4.html.
\273\ Crutzen et al., 2008.
---------------------------------------------------------------------------
Direct N2O emissions based on DAYCENT
simulations with an accounting of all N inputs to agricultural soils,
including mineral N fertilizer, organic amendments, symbiotic N
fixation, asymbiotic N fixation, crop residue N, and mineralization of
soil organic matter. Colorado State University will provide (1) the
total emission rate on an acre basis for each simulated bioenergy crop
in the 63 FASOM regions and (2) a total emissions for each N source.
Indirect N2O emissions on a per acre basis
using results from DAYCENT simulations of volatilization, leaching and
runoff of N from each bioenergy crop included in the analysis for the
63 FASOM regions, combined with IPCC
[[Page 25028]]
factors for the N2O emission associated with the simulated N
losses.
The analyses with updated N2O estimates are not yet
complete and are not included in this proposal. We expect to complete
these analyses for the final rule.
Livestock Emissions: GHG emissions from livestock have two main
sources: enteric fermentation and manure management. Enteric
fermentation produces methane emissions as part of the normal digestive
processes in animals. The FASOM modeling reflects changes in livestock
enteric fermentation emissions due to changes in livestock herds. As
more corn is used in producing ethanol the price of corn increases,
driving changes in livestock production costs and demand. The FASOM
model predicts reductions in livestock herds. IPCC factors for
different livestock types are applied to herd values to get GHG
emissions. The management of livestock manure can produce methane and
N2O emissions. Methane is produced by the anaerobic
decomposition of manure. N2O is produced as part of the
nitrogen cycle through the nitrification and denitrification of the
organic nitrogen in livestock manure and urine. FASOM calculates these
manure management emissions based on IPCC default factors for emissions
factors from the different types of livestock and management methods.
Manure management emissions are projected to be reduced as a result of
lower livestock animal numbers. Use of distiller grains (DGs), as
discussed in Section VI.B.5.b, has been shown to decrease methane
produced from enteric fermentation if replacing corn as animal
feed.\274\ This effect is not currently captured in the models but will
be considered for the final rule.
---------------------------------------------------------------------------
\274\ Salil Arora, May Wu, and Michael Wang, ``Update of
Distillers Grains Displacement Ratios for Corn Ethanol Life-Cycle
Analysis,'' September 2008. See http://www.transportation.anl.gov/pdfs/AF/527.pdf.
---------------------------------------------------------------------------
Methane from Rice: Most of the world's rice, and all rice in the
United States, is grown in flooded fields. When fields are flooded,
aerobic decomposition of organic material gradually depletes most of
the oxygen present in the soil, causing anaerobic soil conditions. Once
the environment becomes anaerobic, methane is produced through
anaerobic decomposition of soil organic matter by methanogenic
bacteria. FASOM predicts changes in rice acres resulting from the RFS2
program and calculates changes in methane emissions using IPCC factors.
ii. International Agricultural Sector GHG Impacts
Agricultural Sector Inputs: The FAPRI model does not directly
provide an assessment of the GHG impacts of changes in international
agricultural practices (e.g., changes in fertilizer load and fuels
usage), however it does predict changes in the land area and production
by crop type and by country. We therefore determined international
fertilizer and energy use based on international data collected by the
Food and Agriculture Organization (FAO) of the United Nations and the
International Energy Agency (IEA). We used the historical trends based
on these FAO and IEA data to project chemical and energy use in 2022.
Additional details on the data used are included in DRIA Chapter 2. We
intend to review input changes required to increase yields for the
final rule and request comment on the extent to which historic trends
adequately project what could occur in 2022 or what alternative
assumptions should be made and the bases for these assumptions. For
example, will changes in farming practices or seed varieties likely
result in significantly different impacts on fertilizer use
internationally than suggested by recent trends? Additionally, we
intend to have the selection and application of this data peer reviewed
before the final rule.
N2O Emissions: For international N2O
emissions from crops, we apply the IPCC emissions factors based on
total amount of fertilizer applied and N2O impacts of crop
residue by type of crop produced. As noted above, we are also working
with Colorado State University to update these factors as part of the
final rule analysis. Additional details on the factors used are
included in DRIA Chapter 2.
Livestock Emissions: Similar to domestic livestock impacts
associated with an increase in biofuel production, FAPRI model predicts
international changes in livestock production due to changes in
commodity prices. The GHG impacts of these livestock changes, including
enteric fermentation and manure management GHG emissions, were included
in our analysis. Unlike FASOM, the FAPRI model does not have GHG
emissions built in and therefore livestock GHG impacts were based on
activity data provided by the FAPRI model (e.g., number and type of
livestock by country) multiplied by IPCC default factors for GHG
emissions. We seek comments on the extent to which the use of this
methodology is appropriate.
Rice Emissions: To estimate rice emission impacts internationally,
we used the FAPRI model to predict changes in international rice
production as a result of the increase in biofuels demand in the U.S.
Since FAPRI does not have GHG emissions factors built into the model,
we applied IPCC default factors by country based on predicted changes
in rice acres. We seek comments on this methodology.
b. Land Use Change
We are also addressing GHG emissions associated with land use
changes that occur domestically and internationally as a result of the
increase in renewable fuels demand in the U.S. Key questions we address
in this analysis include the land area converted to crop production,
where those acreage changes occur, lands types converted, and the GHG
emission impacts associated with different types of land conversion.
EPA recognizes that analyzing international impacts of land use
change can introduce additional uncertainty to the GHG emissions
estimates. At this time, we do not have the same quality of data for
international crop production and projected future trends as we do for
the United States. For example, prediction of the economic and
geographic development of developing country agricultural systems is
far more difficult than prediction of future U.S. agricultural
development. The U.S. has a very mature agriculture system in which the
high quality agricultural lands are already under production and the
infrastructure to move crops to market is already in place. This is not
necessarily the case in other countries. Some very large countries
expected to play a significant role in future agricultural production
are still developing their agricultural system. Brazil, for example,
has vast areas of land that may be suitable for commercial agricultural
production that would allow for significant expansion in crop lands.
One of the restraints on expansion is the relative lack of
infrastructure (e.g., road and rail systems) that would allow shipment
of expanded crop production to market. Identifying what type of land is
converted internationally and the emissions associated with this land
conversion can significantly affect our assessment of GHG impacts. We
present a range of results for differences in these and other
assumptions in Section VI.C.2, and we seek comment on our approach so
that the final rule will use the best science to provide credible
estimates of lifecycle GHG emissions for each biofuel.
[[Page 25029]]
i. Amount of Land Converted
The main question regarding the amount of new land needed to meet
an increasing demand for biofuels hinges on assumptions about the
intensification of existing production versus expansion of production
to other lands. This interaction is driven by the relative costs and
returns associated with each option, but there are other factors as
described below.
Co-Products: One factor determining the amount of new crop acres
required under an increased biofuel scenario is the treatment of co-
products. For example, distillers grains (DGs) are the major co-product
of dry mill ethanol production that is also used as animal feed.
Therefore, using the DGs as an animal feed to replace the use of corn
tends to offset the loss of corn to ethanol production, and reduces the
need to grow additional corn to feed animals. As the renewable fuels
industry expands, the handling and use of co-products is also
expanding. Some uncertainty is associated with how these co-products
will be used in the future (e.g., whether it can be reformulated for
higher incorporation into pork and poultry diets, whether it will be
dried and shipped long distances, whether fractionation will become
widespread).
Both our FASOM and FAPRI models account for the use of DGs in the
agricultural sector. The FASOM and FAPRI models both assume that a
pound of co-product would displace roughly a pound of feed. However, a
recent paper by Argonne National Laboratory \275\ estimates that 1
pound of DGs can displace more than a pound of feed due to the higher
nutritional value of DGs compared to corn.
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\275\ Salil et al., 2008.
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The Argonne replacement ratios do not take into account the dynamic
least cost feed decisions faced by livestock producers. The actual use
of DGs will depend on the maximum inclusion rates for each type of
animal (based on the digestibility of DGs), the displacement ratio for
each type of animal (based on DGs energy and protein content), and the
adoption rate (based on the feed value relative to price). Furthermore,
as world vegetable oil prices increase, dry mill ethanol producers will
have an incentive to extract the corn oil from the DGs. This step
changes the nutritional content of the DGs, which results in different
replacement rates than the ones currently used in FASOM or described by
Argonne. As we plan to evaluate and incorporate a least cost feed
rationing approach for the final rule, we invite comment on the
expected future uses of DGs and their displacement ratios.
Crop Yields: Assumptions about yields and how they may change over
time can also influence land use change predictions. Domestic yields
were based on USDA projections, extrapolated out to 2022. In 2022, we
estimate that the U.S. average corn yield will be approximately 180
bushels/acre (a 1.6% annual increase consistent with recent trends) and
average U.S. soybean yields will be approximately 50 bushels per acre
(a 0.4% annual increase).\276\ Using the FASOM model, we conducted a
sensitivity analysis on the impact of higher and lower yields in the
U.S. Details on this scenario are included in DRIA Chapter 5.1.
International yields changes are also based on the historic trends. The
FAPRI model contains projected yields and yield growths that are
generally lower in other countries compared to the U.S. We request
comment on the projected increase in crop yields in the U.S (including
consideration of how emerging seed types might be expected to increase
average crop yields). We also request comment on the use of historical
trends to predict future agricultural production in other countries and
request information on alternative methodologies and supporting data
that would allow us to base our predictions on alternative assumptions.
---------------------------------------------------------------------------
\276\ Note that these same assumptions apply in both the
reference case and the control cases.
---------------------------------------------------------------------------
The FASOM and FAPRI models currently do not take into account
changes in productivity as crop production shifts to marginal acres or
the impact of price induced yield changes on land use change. We would
expect these two factors could work in opposite directions and
therefore could tend to offset each other's impacts. Marginal acres in
fully developed agricultural systems are expected to have lower yields,
because most productive acres are already under cultivation. This may
not be the case in developing systems where prime agricultural lands
are not currently in full production due to, for example, lack of
supporting infrastructure. Changes in agricultural inputs (e.g.,
fertilizer, pesticides) can also change crop yield per acre. Higher
commodity prices might provide an incentive to increase production in
existing acres. If the costs of increasing productivity on existing
land were minimal relative to the value of the increased production,
then agricultural landowners would presumably adopt these productivity-
enhancing actions under the reference case. Although it is reasonable
to assume a trend wherein some productivity-enhancing practices may
become profitable if commodity prices are high enough such as might
occur as the result of increased biofuel production, it is not clear
that farmers would find significant increases in production per acre
profitable. If crop yields either domestically or international are
significantly impacted by higher commodity prices driven by general
increase in worldwide demand, this could affect our assessment of land
use impacts and the resulting GHG emissions due to increased biofuel
demand in the U.S. However, as described in Section IX, the change in
commodity prices associated with the increase in U.S. biofuel as a
result of the EISA mandates are very small and perhaps not large enough
to induce significant increased yield changes. We invite comment on
projected yields and the potential impact of increased use of marginal
lands and price induced yield changes. For the final rule we plan to
explicitly model the impact of price induced yield changes.
Land Conversion Costs: The assumed cost associated with different
types of land conversion can also play a key role in determining how
much land will be converted. In FASOM, the decision to convert land
from pasture or forest to cropland is based on whether the landowner
can increase the net present value of expected returns through
conversion (including any costs of conversion). Among other things, the
decision to convert land depends on regional yields, costs, and other
factors affecting profitability and on the returns to alternative land
uses. In other words, FASOM assumes that land conversion is based on
maximizing profits rather than minimizing costs. Additional details on
land conversions costs incorporated in FASOM are included in DRIA
Chapter 2.
FAPRI does not explicitly model land conversion costs, however the
international production supply curves used by the FAPRI model
implicitly take into account conversion costs. FAPRI's supply curves
are based on historical responses to price changes, which take into
account the conversion costs of land, based on expected future returns
associated with land conversion. Thus, we believe that our assessments
of international land use changes are based on economic land-use
decisions.
ii. Where Land is Converted
The first step in determining what domestic and international land
will be converted due to biofuels production is to estimate the extent
to which the increased demand for biofuel feedstock
[[Page 25030]]
will be met through increased U.S. agriculture production or reductions
in U.S. exports.
This question has several implications. For example, U.S.
agriculture production is typically more energy and input intensive but
has higher yields than agricultural production in other parts of the
world. This implies that increased production in the U.S. has higher
input GHG emission impacts but lower land use change impacts compared
to overseas production. In addition, the types of land where
agriculture would expand would be different in the U.S. vs. other parts
of the world.
EPA's analysis relies on FASOM predictions to represent changes in
the U.S. agricultural sector, including land use, and on FAPRI to
predict the resulting international agricultural sector impacts
including the amount of additional cropland needed under different
scenarios. The impact on the international agricultural sector is
highly dependent on the U.S. export assumptions. As the FASOM model was
used to represent domestic agricultural sector impacts with an assumed
export picture, the international agricultural sector impacts from
FAPRI needed to be based on a consistent set of export assumptions. We
worked with FASOM and FAPRI modelers to ensure this consistency. This
involved coordinating crop yields, ethanol yields and co-product use,
assumptions regarding CRP acres, a consistent export response, and a
consistent livestock demand and feed use in both models.
As shown in Chapter 2 of the DRIA, coordination of assumptions has
generated a consistent export picture response from both the FASOM and
FAPRI model for the majority of biofuel and feedstock scenarios
considered. Differences in responses in the biodiesel scenario remain
between the two models. FASOM assumes more biodiesel will come from new
soybean acres (but total domestic acres are relatively constant as
reductions in other crops offset the increase in soybean acres). In
comparison, FAPRI contains more types of oil seed crops and has a more
elastic demand in the soybean oil market. The FAPRI model also allows
for some corn oil fractionation from DGs, which can be used as a
substitute for soybean oil. The FASOM model predicts a larger change in
net exports than the FAPRI model. Since we are using the FAPRI model as
the basis for estimating international land use changes, we may be
underestimating the international land use change emissions associated
with soybean based biodiesel. For the final rule, EPA will work, in
particular, to resolve the differences in soybean production impact
between the models. This, too, may modify our assessment of the
biodiesel lifecycle GHG emissions.
Due to the wide range of carbon and biomass properties associated
with land in different parts of the world, the location of crop
conversion is also important to our lifecycle analysis. For example, an
average acre of forest in Southeast Asia stores a much larger quantity
of carbon than a typical acre of forest in Northern Europe. The FAPRI
model provides estimates of the acreage change by country and crop that
result from a decrease in U.S. exports due to the increase in U.S.
biofuel demand. These estimates are based on historic responsiveness to
changes in prices in other countries. Implicit in these supply curves
are the costs associated with converting new land to crop production
and the relative competitiveness of each country to increase production
based on production costs, yields, transportation costs, and currency
fluctuations. FAPRI also includes in its baseline projections of future
population growth, GDP growth, and other macroeconomic changes. FAPRI
also takes into account the fact that not all U.S. exports will need to
be made up in international production, as there is a small decreases
in demand due to shifts in crop production and higher prices.
iii. What Type of Land is Converted
In the same way that the location of land conversion is important,
the type of land that is converted is critical to the magnitude of
impact on the GHG emissions associated with biofuel production. For
example, the conversion of rainforest results in a much larger increase
in GHG emissions than the conversion of grassland. There are several
options for determining what type of land will be converted to crop
acreage. One option is to model land rental rates for different types
of land (e.g., forest, pasture, and crop production), and allow the
model to choose the type of land that is expected to have the highest
net returns. This approach is used by FASOM on the domestic side.
Another option is to use historical land conversion trends in a given
country or region. The FAPRI/Winrock approach uses this approach for
international land use conversion.
Domestic: The FASOM model includes competition between land types,
agriculture, pasture, and forest land. The interaction is based on
providing the highest rate of return across the different land types.
Therefore domestically we have the ability to explicitly model what
types of land would be converted to increased agriculture based on the
rates of return for different land types for the 63 regions in FASOM.
For this draft proposal we incorporated the agricultural component
(which includes both existing cropland and pasture) of the FASOM model,
but not the forestry component (see Section IX.A for explanation).
Therefore, this analysis assumes that all additional cropland predicted
by FASOM comes from pasture. As we incorporate the forestry component
for the final rule analysis we would expect to see more interaction
between the forestry and agriculture sector such that there may be
conversion of forest to agriculture based on additional cropland
needed. While we do not know if forest will be converted to cropland or
the extent that this might occur, if domestic forests were converted to
cropland, we would expect domestic GHG emissions would increase. This
work will be incorporated for our final rule.
International: Basing land use change on the economics and rates of
return of different land uses offers advantages for capturing potential
future land use changes. However, the only model potentially capable of
fully incorporating this calculation internationally, GTAP, is still in
the process of being updated and modified for this purpose. Thus, EPA
has chosen to use historical patterns as identified by satellite images
to estimate future land conversion. This approach is referred to here
as the FAPRI/Winrock approach because it relies on the integration of
each of these tools.
EPA believes that FAPRI/Winrock is a scientifically credible
modeling approach at this time. However, we will continue to work with
the GTAP model to help test the results generated by our primary
approach.
FAPRI/Winrock
Since FAPRI does not contain information on what type of land is
being converted into cropland, we worked with Winrock International, a
global nonprofit organization, to address this question. A key
advantage of Winrock is that they can accurately measure and monitor
trends in forest and land use change, forest carbon content,
biodiversity, and the impact of infrastructure development.
Furthermore, several of the Winrock staff were involved in the
development of the IPCC land use change good practice guidance and are
widely recognized as the leaders in this field.
Using satellite data from 2001-2004, Winrock provided a breakdown
of the types of land that have been converted
[[Page 25031]]
into cropland for a number of key agriculturally producing countries
based on the International Geosphere-Biosphere Programme (IGBP).\277\
The IGBP land cover list includes eleven classes of natural vegetation,
three classes of developed and mosaic lands, and three classes of non-
vegetated lands. The natural vegetation units distinguish evergreen and
deciduous, broadleaf and needle-leaf forests, mixed forests, where
mixtures occur; closed shrublands and open shrublands; savannas and
woody savannas; grasslands; and permanent wetlands of large areal
extent. The three classes of developed and mosaic lands distinguish
among croplands, urban and built-up lands, and cropland/natural
vegetation mosaics. Classes of non-vegetated land cover units include
snow and ice; barren land; and water bodies. Winrock aggregated these
categories into five similar classes: five classes of forest were
combined into one, two classes of savanna were combined into one, and
two classes of shrubland were combined into one. The final land cover
categories for this analysis are forest, cropland, grassland, savanna,
and shrubland. The rest of the IGBP categories not of interest to this
analysis were reclassified into the background. The satellite data
represents different types of land cover, which we are using as a proxy
for land use.
---------------------------------------------------------------------------
\277\ U.S. Geological Survey MODIS Data Set Documentation. See
http://edcdaac.usgs.gov/modis/mod12q1v4.asp.
---------------------------------------------------------------------------
A key strength of this approach is that satellite information is
based on empirical data instead of modeled predictions. Furthermore, it
is reasonable to assume that recent land use changes have been driven
largely by economics and recent historical patterns will continue in
the future absent major economic or land use regime shifts caused, for
example, by changes in government policies. We are using the FAPRI
model to predict where in the world, based on economic conditions, the
most likely increase in agriculture production will occur as a result
of the EISA mandates. We are then using the historical satellite data
to address the key question: If additional land is needed for crop
production in a particular country, what type of land will be used? The
Winrock analysis addresses this question by calculating the weighted
average type of land that was converted to cropland between 2001 and
2004. Essentially, we are using the Winrock data to determine the type
of land that is most likely to be converted to cropland, should
additional acres be needed as predicted by FAPRI.
Table VI.B.5-1 shows the percentage of land converted to cropland
between 2001 and 2004 according to the Winrock satellite data analysis
for the countries currently available. We use these percentages to
calculate a weighted average of the types of land converted into
cropland. For example, if FAPRI predicts that one additional acre of
cropland will be brought into production in Argentina, we used the
Winrock data to estimate that 8% on average of that acre will come from
forest, 40% of that acre will come from grassland, 45% of that land
will come from savanna, and 8% of that land will come from shrubland.
Using GTAP might result in different percentage weights.
Table VI.B.5-1--Types of Land Converted to Cropland by Country
[In percent]
----------------------------------------------------------------------------------------------------------------
Country Forest Grassland Savanna Shrub
----------------------------------------------------------------------------------------------------------------
Argentina....................................... 8 40 45 8
Brazil.......................................... 4 18 74 4
China........................................... 17 38 23 21
EU.............................................. 27 16 36 21
India........................................... 7 7 33 53
Indonesia....................................... 34 5 58 4
Malaysia........................................ 74 3 19 3
Nigeria......................................... 4 56 36 4
Philippines..................................... 49 5 44 3
South Africa.................................... 10 22 53 15
----------------------------------------------------------------------------------------------------------------
Source: Winrock Satellite Data (2001-2004).
We are assuming that the weighted average, resulting from
agriculture demand as well as other possible drivers, is a reasonable
estimate of the land use change attributable to increased agricultural
demand. A shortcoming of this approach is that it assumes that when new
crop acres are needed to meet increased agricultural demand these crop
acres will follow the average pattern of recent historical land
conversion, recognizing that this pattern is based on a variety of
drivers of land use change, not all of which are associated with
agricultural demand. This approach is not able to isolate from the
historical pattern the land use changes stemming just from increased
agricultural demand. For example, it is likely that in some cases trees
are being removed from forests for the value of the wood. However,
having removed valuable wood, additional clearing may occur to allow
the land to be used for pasture or cropland. In that case the GHG
emissions associated with the removal of the trees would not occur as a
consequence of increased agricultural demand, but as a consequence of
increased demand for the wood, while the GHG emissions associated with
the additional clearing would occur as a consequence of the
agricultural demand.
As a result, the Winrock data also does not distinguish between the
land-use impacts associated with one crop versus another. Indeed, at
least in the case of sugarcane production in Brazil, a number of
researchers argue that expanded sugarcane production is likely to occur
in significant part through the use of degraded or abandoned pasture
land without additional land use impact.\278\ These research reports
suggest that general historical trends in land use change to grow crops
in Brazil may not pertain to expected growth in sugarcane production.
Ideally, an analysis of a U.S. biofuels policy's influence on land use
change would
[[Page 25032]]
model the marginal impact that U.S. biofuel would have on land use and
land use change in addition to baseline land use change. Use of
historic land use change data is capturing some of this baseline land
use change. Comments are requested on our approach of assuming
historical land use changes will continue to be followed in response to
increased agricultural demand associated with our biofuel policy. We
also invite comment on what alternative methodologies and data are
available, if any, to better link the impacts of biofuels to land use
change. To the extent additional information or data may be available
for certain countries such as the example of Brazil, we also ask how
this country-specific data and similar information might best be
integrated with the modeling results otherwise available. Furthermore,
to the extent different government policies can shift land use patterns
(e.g., through regulations, financial supports), these weighted
averages could change in the future. We request comment on whether
these government policies and regulations should be incorporated into
the future land use change calculations and the best methodology for
taking into account these changes.
---------------------------------------------------------------------------
\278\ See for example ``Mitigation of GHG emissions using
sugarcane bio-ethanol--Working Paper'' by Isaias C. Macedo and
Joaquim E. A. Seabra, and ``Prospects of the Sugarcane Expansion in
Brazil: Impacts on Direct and Indirect Land Use Changes--Working
Paper'' by Andre Nassar et al., both received by EPA October 13,
2008.
---------------------------------------------------------------------------
The Winrock data and analyses present an aggregate picture of land
use changes; they cannot predict the nature of the land use change that
will result due to an additional acre of corn planted in a country
versus an additional acre of sugarcane or soybeans. In reality,
sugarcane may be more suitable for planting in different regions with
different soil types compared to corn or soybeans. However, because we
are using weighted averages to characterize the type of land that is
converted to crop acres, all additional crop acres in a particular
country are treated identically.
Winrock also provides information on land conversions between other
categories (e.g., forest to savanna). For one set of GHG analyses, we
assumed that land taken out of actively managed use \279\ (e.g.,
pasture used for livestock production) would have to be replaced with
new pasture acreage, thereby capturing some of the domino effect
associated with converting previously productive land into cropland.
Therefore, in addition to land conversion shown in Table VI.B.5-1, we
also include land conversion to replace some of the grassland and
savanna that is used as pasture. An alternative approach would be to
assume that no additional land is necessary, since there is a
significant amount of pastureland that could be used more intensively
for grazing purposes. For example, as noted above, in Brazil almost all
of the direct land conversion associated with expanding sugarcane
production is coming out of existing pasture land, in some cases,
depleted, low value pasture land, that may have relatively low levels
of stored carbon compared to other land. Also in Brazil there is a
trend toward more intensive use of existing pasture land by grazing
higher numbers of cattle per unit of pasture, decreasing the need to
replace pasture converted to cropland. This more intensive use of
pasture is encouraged by two factors: improved grasses which can
sustain more intensive grazing and lack of transportation
infrastructure which tends to constrain geographic expansion of pasture
lands. However, we also note that depleted cropland in Brazil might
also be suitable for other crop production. To extend sugarcane limits
to production of these other crops on this land, the indirect effect
could be that these crops move into other areas of Brazil and resulting
in increased emissions due to land use change. We invite comment on
alternative methodologies for predicting land use changes in particular
in other countries. Some alternative methodologies are described in
more detail in Chapter 2 of the DRIA.
---------------------------------------------------------------------------
\279\ GTAP Land Cover Data (2000-2001).
---------------------------------------------------------------------------
The FAPRI model results have been used in peer reviewed literature
in conjunction with satellite data to assess land use changes \280\ and
we also believe it is an appropriate method for projecting biofuel
induced land use changes. However, we recognize the uncertainty
associated with this approach and, in addition to seeking public
comment, we plan to conduct an expert peer review of the data and
methods used, including the appropriateness of using historic satellite
data to project future land use changes.
---------------------------------------------------------------------------
\280\ Searchinger et al., 2008.
---------------------------------------------------------------------------
iv. What Are the GHG Emissions Associated With Different Types of Land
Conversion?
Our estimates of domestic land use change GHG emissions are based
on outputs of the FASOM model. As we are just using the agricultural
portion of the FASOM model for this analysis the land use change GHG
emissions are limited to changes in land use for existing crop and
pasture land. Some of that crop land could currently be fallow and some
of the pasture land could currently be unused. However, no new crop or
pasture land (beyond some Conservation Reserve Program (CRP) land due
to legislative changes in the program) is added compared to current
levels. Thus FASOM only models shifts in the use of this land.
Changes in the agricultural sector due to increased corn used for
ethanol have impacts on land use change in a number of ways. FASOM
explicitly models change in soil carbon from increased crop production
acres and from different types of crop production. FASOM also models
changes in soil carbon from converting non crop land into crop
production. Land converted to crop land could include pasture land. As
recommended by USDA, we are assuming that 32 million acres of CRP land
will remain in that program even if crop prices increase and thus
increase land values. This assumption is consistent with the 2008 Farm
Bill, which limits CRP acres to 32 million. A sensitivity analysis on
this assumption is included in Chapter 5 of the DRIA.
For the international impacts, we used the 2006 IPCC Agriculture,
Forestry, and Other Land Use (AFOLU) Guidelines \281\ and the Winrock
provided GHG emissions factors for each country based on the weighted
average type of land converted. GHG emissions estimates were based on
immediate releases (e.g., changes in biomass carbon stocks, soil carbon
stocks, and non-CO2 emissions assuming the land is cleared
with fire) and foregone forest sequestration (the future growth in
vegetation and soil carbon). Additional details on these calculations
are included in Chapter 2 of the DRIA. For the emissions factors
presented, we assume forests cleared would have continued to sequester
carbon for another 80 years, based on the amount of time it takes for
forests to reach a general equilibrium stage. We request comment on
whether it is appropriate to include foregone sequestration in the GHG
emissions estimates. Carbon soil calculations \282\ take into account
the annual changes in carbon content in the top 30 centimeters of soil
over the first 20 years, based on IPCC recommendations.\283\ We also
request comment on whether soil carbon calculations should be based on
the top 30 centimeters of soil. These emission factors do not include
credits for harvested wood products, based on the expectation that they
would have a
[[Page 25033]]
very small impact on our estimates of land use change emissions.
However, we intend to analyze the impact of wood product credits for
the final rule. We invite comment on whether it is appropriate to
include wood product credits in the GHG emissions estimates.
---------------------------------------------------------------------------
\281\ 2006 IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 4, Agriculture, Forestry and Other Land Use
(AFOLU). See http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol4.html.
\282\ See ftp://www.daac.ornl.gov/data/global_soil/IsricWiseGrids.
\283\ 2006 IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 4, Section 5.3.3.4.
---------------------------------------------------------------------------
GHG emissions associated with land use changes vary significantly
based on the type of land and the geographic region. For example, the
GHG emissions associated with converting an acre of grassland to
cropland in China are lower than the emissions associated with
converting an acre of shrubland to cropland in China. Similarly, the
GHG emissions associated with converting an acre of forest to cropland
in Malaysia are larger than the emissions associated with converting an
acre of forest in Nigeria to cropland. Where country specific emission
factors were not available in time for the proposal, we used world
average. For the proposal, we focused on the countries with the largest
projected changes in crop acreage. The Winrock data currently covers
63% of total land use change acres associated with corn ethanol, 53% of
the acres associated with biodiesel, 57% of the acres associated with
switchgrass, and 87% of the acres associated sugarcane ethanol. We will
continue to add additional countries for our analysis for the final
rule. Two changes that may impact these results for the final rule
include the addition of perennial crops and the conversion on land with
peat soils. We request comment on our calculation of emission factors
due to land use change; improved data and assumptions are specifically
requested. Additionally, we plan to have the calculation of these
emissions factors reviewed by experts in this field. Details on the
Winrock estimates are included in the DRIA Chapter 2.
GTAP Approach:
GTAP is an economy-wide general equilibrium model that was
originally developed for addressing agricultural trade issues among
countries. The databases and versions of the model are widely used
internationally.\284\ Since its inception in 1993, GTAP has rapidly
become a common ``language'' for many of those conducting global
economic analysis. For example, the WTO and the World Bank co-sponsored
two conferences on the so-called Millennium Round of Multilateral Trade
talks in Geneva. Here, virtually all of the quantitative, global
economic analyses were based on the GTAP framework. Over the past few
years, a version of the model was developed to explicitly model global
competition among different land types (e.g., forest, agricultural
land, pasture) and different qualities of land based on the relative
value of the alternative land-uses. More recently, it was modified to
include biofuel substitutes for gasoline and diesel. In simulating land
use changes due to biofuels production, GTAP explicitly models land-use
conversion decisions, as well as land management intensification. For
example, it allows for price-induced yield changes (e.g., farmers can
reallocate inputs to increase yields when commodity prices are high)
and considers the marginal productivity of additional land (e.g.,
expansion of crop land onto lower quality land as a result of the
increased use of biofuels). Most importantly, in contrast to other
models, GTAP is designed with the framework of predicting the amount
and types of land needed in a region to meet demands for both food and
fuel production. The GTAP framework also allows predictions to be made
about the types of land available in the region to meet the needed
demands, since it explicitly represents different land types within the
model.
---------------------------------------------------------------------------
\284\ https://www.gtap.agecon.purdue.edu.
---------------------------------------------------------------------------
The global modeling of land-use competition and land management
decisions is relatively new, and evolving.\285\ GTAP does not yet
contain cellulosic feedstocks in the model. In addition, GTAP does not
currently contain unmanaged land, which could be a major factor driving
current GTAP land use projections and is a significant potential source
of GHG emissions. We expect to update GTAP with cellulosic feedstocks
and unmanaged land in time for the final rule.
---------------------------------------------------------------------------
\285\ See Hertel, Thomas, Steven Rose, Richard Tol (eds.), (in
press). Economic Analysis of Land Use in Global Climate Change
Policy, Routledge Publishing.
---------------------------------------------------------------------------
Our proposal is therefore based on the FAPRI/Winrock estimates.
There are advantages and disadvantages associated with any model choice
and we have chosen the FAPRI/Winrock combination as the best approach
available for preparing the proposal. Although we have not relied on
the current version of GTAP for the principal analyses in this
proposal, others have used versions of the current model to assess land
use changes which could result from expanded biofuel demand. The
California Air Resources Board as part of the analysis for their low
carbon fuel standard used GTAP to model indirect land use change for
biofuels. More information on their program and GTAP analysis can be
found at http://www.arb.ca.gov/fuels/lcfs/lcfs.htm. Furthermore,
researchers from Purdue University have released a report on work using
GTAP to look at land use change associated with corn ethanol production
scenarios.\286\ This work was partially funded by Argonne National Lab
for possible inclusion in the GREET model. We anticipate additional
refinements will be made to the GTAP model between the proposal and
final rule and we will include this information and results in the
docket as they become available. We invite comments in this NPRM on the
use of the GTAP model in helping to establish the GHG emissions
estimates for the final rule.
---------------------------------------------------------------------------
\286\ Land Use Change Carbon Emissions due to US Ethanol
Production, Wallace E. Tyner, Farzad Taheripour, Uris Baldos,
January 2009. Available at http://www.agecon.purdue.edu/papers/biofuels/Argonne-GTAP_Revision%204a.pdf.
---------------------------------------------------------------------------
v. Assessing GHG Emissions Impacts Over Time and Potential Application
of a GHG Discount Rate
When comparing the lifecycle GHG emissions associated with biofuels
to those associated with gasoline or diesel emissions, it is critical
to take into consideration the time profile associated with each fuel's
GHG emissions stream. With gasoline, a majority of the lifecycle GHG
emissions associated with extraction, conversion, and combustion are
likely to be released over a short period of time (i.e., annually) as
crude oil is converted into gasoline or diesel fuel which quickly pass
to market. This means that the lifecycle GHG emissions of a gallon of
gasoline produced one year are unlikely to vary much from the lifecycle
GHG emissions of a similar gallon of gasoline produced in a subsequent
year.
In contrast, the lifecycle GHG emissions from the production of a
typical biofuel may continue to occur over a long period of time. As
with petroleum based fuels, renewable fuel lifecycle GHG emissions are
associated with the conversion and combustion of biofuels in every year
they are produced. In addition, GHG emissions could be released through
time if new acres are needed to produce corn, soybeans or other crops
as a replacement for crops that are directly used for biofuel
production or displaced due to biofuels production. The GHG emissions
associated with converting land into crop production would accumulate
over time with the largest release occurring in the first few years due
to clearing with fire or biomass decay. After the land is converted,
moderate amounts of soil carbon would continue to be released for
[[Page 25034]]
approximately 20 years.\287\ Furthermore, there would be foregone
sequestration associated with forest clearing as this forest would have
continued to sequester carbon had it not been cleared for approximately
80 years.
---------------------------------------------------------------------------
\287\ Following Section 5.3.3.4 of the IPCC AFOLU guidelines,
the total difference in soil carbon stocks before and after
conversion was averaged over 20 years.
---------------------------------------------------------------------------
Therefore, we have included an analysis which considers GHG
emissions from land use change that may continue for up to 80 years,
based on our estimate of the average length of foregone sequestration
after a forest is cleared. Annual foregone sequestration rates were
estimated by ecological region using growth rates for forests greater
then 20 years old from the 2006 IPCC guidelines for Agriculture,
Forestry and Other Land Use.\288\ Studies have estimated that new
forests grow for 90 years to over 120 years.\289\ More recent estimates
suggest that old growth forests accumulate carbon for up to 800
years.\290\ The foregone sequestration methods used in this proposal
are within the range supported by the scientific literature and the
2006 IPCC guidelines. Details of the foregone sequestration estimates
are included in DRIA Chapter 2. We seek comment on our estimate of the
average length of annual foregone forest sequestration for
consideration in biofuel lifecycle GHG analysis.
---------------------------------------------------------------------------
\288\ Table 4.9 from the 2006 GL AFOLU was used to estimate the
lost C sequestration of forests that were converted to another land
use.
\289\ See Greenhouse Gas Mitigation Potential in U.S. Forestry
and Agriculture, EPA Document 430-R-05-006 for a discussion of the
time required for forests to reach carbon saturation.
\290\ Luyassert, S et al., 2008. Old-growth forests as global
carbon sinks. Nature 455: 213-215. Link: http://www.nature.com/nature/journal/v455/n7210/abs/nature07276.html.
---------------------------------------------------------------------------
Figure VI.B.5-1 shows how lifecycle GHG emissions vary over time
for a natural gas fired dry mill corn ethanol plant assuming that all
land use change occurs in 2022. While biomass feedstocks grown each
year on new cropland can be converted to biofuels that offer an annual
GHG benefit relative to the petroleum product they replace, these
benefits may be small compared to the upfront release of GHG emissions
from land use change. Depending on the specific biofuel in question, it
can take many years for the benefits of the biofuel to make up for the
large initial releases of carbon that result from land conversion
(e.g., the payback period). As shown in Figure VI.B.5-1, the payback
period for a natural gas-fired dry mill corn ethanol plant which begins
operation in 2022 would be approximately 33 years. We present a similar
payback period calculation for the full range of biofuels analyzed in
Section VI.C.
[GRAPHIC] [TIFF OMITTED] TP26MY09.008
As required by EISA, our analysis must demonstrate whether biofuels
reduce GHG emissions by the required percentage relative to the 2005
petroleum baseline. A payback period alone cannot answer that question.
Since the payback period alone is not sufficient for our analysis, we
have considered accounting methods for capturing the full stream of
emissions and benefits over time. There are at least two necessary
criteria for the accounting methods we have considered. First, they
must provide an estimate of renewable fuel lifecycle GHG emissions that
is consistent over time. Otherwise, for example, all of the upfront
emissions due to land clearing would be assigned to corn ethanol
produced in the first year, and none of those emissions to corn ethanol
produced the following years even though this land use change is
central to the production over these following years. Second, the
accounting method must also provide a common metric that allows for a
direct comparison of biofuels to gasoline or
[[Page 25035]]
diesel. When accounting for the time profile of lifecycle GHG
emissions, the two most important assumptions in the determination of
whether a biofuel meets the specified emissions reduction thresholds
include: (1) The time period considered and (2) the discount rate
(which could be zero) applied to future emissions streams.
Time Periods Considered
The illustration of the payback period in Figure VI.B.5-1
demonstrates the importance of the time period over which to consider
both the lifecycle GHG emissions increases associated with the
production of a biofuel as well as the benefits from using the biofuel.
As mentioned above, based on our lifecycle GHG analysis for this
proposed rule we estimate that the payback period for corn ethanol
produced in a natural gas-fired dry mill is approximately 33 years. In
this case, if we measure GHG impacts over a time period of less than 33
years we will determine that the total corn ethanol produced over this
time period increases lifecycle GHG emissions. Conversely, total corn
ethanol production will reduce net lifecycle GHG emissions if we look
beyond 33 years, with net emissions reductions increasing the further
into the future we extend our analysis. To inform our decision of which
time period for analysis is most appropriate, we must consider a number
of factors including but not limited to the length of time over which
we expect a particular biofuel to be produced, the time over which
biofuel production continues to impact GHG emissions into the future,
the importance of achieving near-term GHG emissions reductions, and the
increasing uncertainty of projecting GHG emissions impacts into the
future. Based on these considerations, our discussion of lifecycle
analyses prepared for this proposed rule focuses on time periods of 100
years and 30 years.
There are advantages and disadvantages to using the 100 and 30 year
time frames to represent both emissions impacts as well as emissions
benefits of use of biofuels over time. There are several principal
reasons for using the 100 year time frame. First, greenhouse gases are
chemically stable compounds and persist in the atmosphere over long
time scales that span two or more generations. Second, the 100 year
time frame captures the emissions associated with land use change that
may continue for a long period of time after biofuel-induced land
conversion first takes place.\291\ For example, physical changes in
carbon stocks on unmanaged lands may not slow until after 100 years,
and optimal forest rotation ages can influence greenhouse gas emissions
for 100 years on managed lands. Similarly, a 100 year time frame would
allow estimating the future changes in the land should the need for
these changes due to biofuel production cease. For example, as
discussed in more detail below, if production of a biofuel ended, then
the land use impacts associated with that biofuel would also tend to go
away in a process known as land use reversion. A longer time frame
would allow assessment of the impacts of that land use reversion.
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\291\ Luyassert, S et al., 2008. Old-growth forests as global
carbon sinks. Nature 455: 213-215. Link: http://www.nature.com/nature/journal/v455/n7210/abs/nature07276.html.
---------------------------------------------------------------------------
For a number of reasons we believe that biofuel production could
continue for a long time into the future. As biofuel technologies
advance and production costs are decreased, it is likely that renewable
fuels will become increasingly competitive with petroleum-based fuels.
Another reason for expecting long term biofuel production is that,
unlike a specific facility that has an expected lifetime, the RFS
program does not have a specified expiration date. The expectation that
renewable fuel production will continue for a long time provides
justification for using a longer time frame for analysis, such as 100
years. Another reason for considering an inter-generational time period
such as 100 years for lifecycle GHG analysis is that climate change is
a long-term environmental problem that may require GHG emissions
reductions for many decades.
The 100 year time frame also has drawbacks. A general concern with
projecting impacts over a very long time period is that uncertainty
increases the further the analysis is extended into the future. For
example, a 100 year analysis presumes that production of a particular
biofuel will continue for at least 100 years. Although we expect
renewable fuel production as a whole to continue for a long time, it is
possible that due to changing market conditions or other factors, the
use of first generation biofuels (e.g., corn ethanol) could see a
decline in use over a shorter period of time.
For this proposal, we are also showing the results of analyzing
both GHG emissions impacts of producing a biofuel as well as benefits
from using the biofuel over 30 years, a time frame which has been used
in the literature to estimate the greenhouse gas impacts of
biofuels.292 293 Since a time period such as 30 years would
truncate the potential GHG benefits that accumulate over time, this
second option would reduce the GHG benefits of biofuels relative to
gasoline or diesel compared to assuming a longer time frame for biofuel
production such as 100 years.
---------------------------------------------------------------------------
\292\ Searchinger et al., 2008.
\293\ M. Delucchi, ``A multi-country analysis of lifecycle
emissions from transportation fuels and motor vehicles'' (UCD-ITS-
RR-05-10, University of California at Davis, Davis, CA 2005). See
also http://www.its.ucdavis.edu/people/faculty/delucchi/.
---------------------------------------------------------------------------
One advantage of using a shorter time period is that it is more
``conservative'' from a climate change policy perspective. In general,
the further out into the future an analysis projects, the more
uncertainty is introduced into the results. For example, with a longer
time period for analysis, it is more likely that significant changes in
market factors or policies will change the incentives for producing
biofuels. If a biofuel only has greenhouse benefits when considered in
an extended future time frame, it is not clear that these benefits will
be realized due to the inherent uncertainty of the future. Also,
potential irreversible climate change impacts or future actions in
other sectors of the economy, such as reductions from stationary
sources, could influence the relative importance of renewable fuel GHG
impacts. The timing and severity of these potential irreversible
climate change impacts are clearly uncertain as is the degree to which
near-term lifecycle emissions related to biofuel production influences
these climate change impacts. Given these uncertainties, it may be
appropriate to limit our analysis horizon to a much shorter time period
such as 30 years.
Several disadvantages are also associated with choosing the 30 year
time frame to represent both emissions impacts as well as emissions
benefits. One key disadvantage is that it ignores the potential sources
of GHG emissions impacts of producing biofuel after 30 years such as
foregone sequestration from forests that may have been removed which
could have continuing impacts even after production of a biofuel has
ended. Thus, it doesn't account for the full land use emissions
``signature'' of biofuels. In addition, even if second generation fuels
start to dominate new construction, building a first generation fuel
production facility such as a corn ethanol refinery represents a
significant capital investment. Once the facility is built and
financed, it may continue
[[Page 25036]]
producing biofuel as long as it is covering its operating costs. This
suggests that, once a plant is built, if the variable cost of corn
ethanol production is less than the cost to produce gasoline, then corn
ethanol production at that facility may continue. This economic
advantage may contribute to the longevity of first generation biofuel
production and usage far into the future.
An appropriate time frame for analysis could also be different for
different biofuels. While we could assume that corn ethanol would be
phased out after a shorter time period such as 30 years, it might be
more appropriate to use a longer time period over which to analyze the
benefits of other advanced biofuels such as cellulosic biofuels. It
could be reasonably assumed that cellulosic biofuels will be produced
for more than 30 years, perhaps for 100 years or longer. However, even
if cellulosic biofuels are expected to be produced for 100 years or
longer, a shorter time period, such as 30 years, may still be the most
relevant period over which to assess GHG emissions, given the
importance of near-term emissions reductions and the increasing
uncertainty of future events. We specifically seek comments on the 100
year and 30 year time frames discussed in this proposal. We also seek
general comments on the most appropriate time periods for analysis of
biofuels, and whether we should use different time periods for
different types of renewable fuels.
Another way to look at the time period issue, which we have not
specifically analyzed for this proposed rule, would separate the time
period into two parts. The first part would consider how long we expect
production of a particular biofuel to continue into the future. We
refer to this concept, which is similar to the project lifetime often
considered in traditional cost benefit analysis, as the ``project''
time horizon. The second part would address the length over which to
account for the changes in GHG emissions due to land use changes which
result from biofuel production. We call this the ``impact'' time
horizon.
Our analysis for this proposed rule has not considered a scenario
where the project time horizon is shorter than impact time horizon.
However, we are considering this option for the final rule. For
example, we could look at a scenario where corn ethanol production
continues for 30 years and land use related GHG emissions are estimated
for 100 years. Specifically, we are considering whether to use 30 years
after 2015 (as an approximation of when ethanol production from corn
starch reaches 15 billion gallons) as a reasonable estimate of when
corn will no longer be used for ethanol production due to advances in
other biofuels and the competing demand to use corn for food rather
than biofuel feedstock. We specifically ask whether a 30 year estimate
of continued corn starch ethanol production (i.e., through 2045) is a
reasonable estimate for assessing the stream of GHG benefits from corn
ethanol use while 100 years would be appropriate for assessing impacts
of the land use change. Under such an assumption a 100 time horizon
would capture the longer term emission impacts of corn ethanol
production (including indirect land use impacts) while the benefits
from 31 through 100 years would be zero since corn ethanol would be
modeled as no longer in use.
In that scenario, we would have to consider the lifecycle GHG
impacts after the production of corn ethanol ends. This would include
the issue of land reversion, or what happens to the land used to
produce a biofuel feedstock after its use for biofuel production has
ceased. A full accounting of land reversion would involve economic
modeling to determine how long we expect production of a particular
biofuel to last, and to determine the land use changes after that
biofuel production ends. Ideally this modeling would extend well beyond
2022 to the point where land reversion is complete, and it would
include projections for global crop yield improvements, population
trends, food demand, and other key factors. For this proposal, we have
not projected the GHG emissions associated with land reversion, but we
plan to consider land reversion in our final rule analysis and we seek
comments on methodologies and approaches for doing this. We also seek
comment on the related issue of how best to estimate how long each type
of biofuel is most likely to continue to be produced, and whether
production of these biofuels is likely to end abruptly or phase out
gradually.
Agricultural and economic models that look beyond 2022 would not
only help to estimate the impacts of land reversion after biofuel
production ends, they would also help to project how evolving
agricultural conditions could influence the lifecycle GHG emissions of
biofuels beyond 2022. For example, corn yields per acre are expected to
continue increasing after 2022; this increase in yields per acre will
decrease the amount of land required to produce a bushel of corn. At
higher yields, fewer acres are required to grow the corn used for the
15 billion gallons of corn starch ethanol modeled for the rule. The
indirect impacts of maintaining 15 billion gallons of corn ethanol
production would similarly be reduced. EPA intends to more carefully
model these transitions in particular to better account for future land
use impacts and we invite comments on methodology, sources of data,
factors that should be considered in assessing whether and when a
particular biofuel such as ethanol from corn starch, for example, will
no longer be produced and recommendations on how to improve on our
assessment of the likely stream of GHG emissions after 2022 that will
result from the EISA mandates.
A complicating consideration in this analysis arises in determining
future use of the land (post-biofuel production) is the fact that
perhaps significant land use change occurred as a result of biofuel
production and that land is now more easily suited for alternative uses
compared to its pre-biofuel state. For example, the demand created by
biofuel production may have justified clearing forested lands and
turning them into productive cropland. Even if the need for the land to
produce crops in response to biofuel demand ceases when the biofuel
production ends, the land will still be in an altered form making it,
for example, more economically available for other crop production than
when it had been forested. How this land is subsequently used can
affect its impact on GHG emissions. If it is used for intensive crop
production, the land will have a much different carbon sequestration
profile, for example, than if it returned to its pre-biofuel forested
state. EPA asks for suggestions on how to best treat these lingering
effects of land use change when attributing the effects of biofuel
demand to uses of land even after biofuel production ends.
For the determination of whether biofuels meet the GHG emissions
reduction required by EISA, we present the results for a range of time
periods, including both 100 years and 30 years in Section VI.C and
specifically invite comment on whether use of a 100 year time frame, a
30 year time frame, or some other time frame, would be most
appropriate.
In addition to this general issue of the appropriate time frames
for analysis, several more specific issues exist. Since it would be
likely that corn starch ethanol production will phase out gradually
rather than stopping all of a sudden in 2045, we also are evaluating
options for estimating the phase out of corn starch ethanol production.
One simplifying assumption would have corn ethanol production phase out
[[Page 25037]]
linearly between 2022 and 2045 as production of other biofuels such as
cellulosic biofuels continue to expand. Comments are requested on the
option of linearly phasing out corn ethanol production from 2022
through 2045 and other approaches for estimating this transition in
corn ethanol production. Finally, its not only corn starch ethanol that
might be replaced in future years. For example, the use of soy oil for
biodiesel fuel production might be replaced by other non-food oils such
as oil from algae. Comments are requested on whether other biofuels
will similarly phase out of use and therefore the land use change
impacts need to be similarly considered.
In addition to seeking comments on all of the issues related to the
time periods for lifecycle analysis, EPA plans to convene a peer review
of the range of time periods considered in this proposed rule. This
peer review will also seek expert feedback on all of the issues raised
above in this section, including how to determine the most appropriate
time periods for consideration in the final rule.
Discounting of Lifecycle GHG Emissions
Economic theory suggests that in general consumers have a time
preference for benefits received today versus receiving them in the
future. Therefore, future benefits are often valued at a discounted
rate. Although discount rates are most often applied to the monetary
valuation of future versus present benefits, a discounting approach can
also be used to compare physical quantities (i.e., total GHG emissions
per gallon of fuel used).
The concept of weighting physical units accruing at different times
has been used in the environmental and resource economics
literature,\294\ and is analogous to valuing the monetary cost and
benefits of a policy, only that in this case the metric that we `value'
is the reduction in GHG emissions. \295\ An important part of the
economic theory of time is the idea that benefits expected to accrue in
the long term are less certain than benefits in the near term. This is
true in the case of GHG emissions changes from biofuel production which
are dependent upon how long biofuel production will continue, how
technologies will develop over time, and other factors. Another reason
to give more weight to near-term emissions changes is that the risks
associated with climate change in the future include the possibility of
extreme climate change and threshold impacts (e.g., species and
ecosystem thresholds, catastrophic events). Increased GHG emissions in
the near-term may be more important in terms of physical damage to the
world's environment. Some scientists, for example, believe that effects
on factors such as arctic summer ice, Himalayan-Tibetan Glaciers, and
the Greenland ice sheet are more likely to be effected by near-term GHG
emissions, causing non-linearities in the effects attributable to GHG
emissions.\296\ Long-term GHG reductions may be too late to mitigate
these irreversible impacts, providing further justification for
discounting GHG emissions changes that are expected in the distant
future. Under this perspective, it would be appropriate to discount the
physical quantities of future emissions, and especially in a long term
analysis of lifecycle GHG emissions. Thus in our analysis with a 100
year time frame, or impact horizon, we discount the value of future GHG
emissions changes.
---------------------------------------------------------------------------
\294\ Herzog et al. 2003 (See http://sequestration.mit.edu/pdf/climatic_change.pdf), Richards 1997, Stavins and Richards 2005 (See
http://www.pewclimate.org/docUploads/Sequest_Final.pdf).
\295\ Sunstein and Rowell, 2007, On Discounting Regulatory
Benefits: Risk, Money, and Intergenerational Equity, Chicago Law
Review.
\296\ Ramanathan and Feng, 2008. On avoiding dangerous
anthropogenic interference with the climate system: Formidable
challenges ahead. Proceedings of the National Academy of Sciences
105:143245-14250.
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Despite the rationale for discounting future GHG emissions changes
discussed above, there are reasons to be cautious about the application
of discounting in lifecycle GHG analysis. One argument is that it may
only be appropriate to discount monetized values. Our lifecycle
analysis estimates GHG emission impacts, not their monetary value, and
under this argument emissions should not be directly discounted.
Rather, the physical GHG emissions should be converted into monetary
impacts, where these monetary impacts are also a function of climate
science. The resulting climate impacts would then have to be translated
into monetary values. This presents significant challenges for
lifecycle GHG analysis because it is difficult to translate dynamic GHG
emissions into a single estimate of physical impacts, much less a
single estimate of monetized impacts. This is the case for a number of
reasons, including the complex physical systems associated with climate
change (e.g., the relationship between atmospheric degradation rates
with atmospheric carbon stocks) that may create non-constant marginal
damages from GHG emissions over time. Furthermore, converting lifecycle
GHG emissions into monetized impacts may be inconsistent with the EISA
definition of lifecycle GHG emissions provided above in Section VI.A.1,
which stipulates that lifecycle GHG emissions are the ``aggregate
quantity of greenhouse gas emissions * * * where the mass values for
all greenhouse gases are adjusted to account for their relative global
warming potential.''
Another argument against discounting GHG emissions changes is the
concept of inter-generational equity, which argues that benefits or
damages affecting future generations merit just as much weight as
impacts felt by current generations. It is argued that this would
invalidate the practice of discounting emissions impacts that could
affect future generations.
Finally, earlier in this section we discussed the possible ranges
of time frames for analyzing the GHG emissions impacts. For shorter
time frames such as 30 years, there would be less uncertainty in the
emissions stream so the benefit of discounting to address uncertainty
is also lessoned.
Comments are requested on the concept of discounting a stream of
GHG emissions for the purpose of estimating lifecycle GHG emissions
from transportation fuels as specified in EISA.
Appropriate Level of Discount Rate
As described in more detail in Section IX on GHG emission reduction
benefits, GHG emissions have primarily consumption effects and inter-
generational impacts, as changes in GHG emissions today will continue
to have impacts on climate change for decades to centuries. If a
discount rate is applied to future GHG emissions, an appropriate
discount rate should be based on a consumption-based discount rate
given that monetized climate change impacts are primarily consumption
effects (i.e., impacts on household purchases of goods and services). A
consumption-based discount rate reflects the implied tradeoffs between
consumption today and in the future. Discount rates of 3% or less are
considered appropriate for discounting climate change impacts, since
they reflect the long run uncertainty in economic growth and interest
rates and the risk of high impact climate damages that could reduce
economic growth.\297\
---------------------------------------------------------------------------
\297\ Technical Support Document on Benefits of Reducing GHG
Emissions, U.S. Environmental Protection Agency, June 12, 2008,
www.regulations.gov (search phrase ``Technical Support Document on
Benefits of Reducing GHG Emissions'').
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[[Page 25038]]
When analyzing the GHG emissions associated with a 100 year time
period, we examined a variety of alternative discount rates (e.g., 0,
2, 3, 7 percent) to show the sensitivity of greenhouse gas emissions
estimates to the choice of the discount rate. A zero discount rate
estimates GHG emission impacts as if each ton of GHG emissions is
treated equally through time. Previous methodologies of lifecycle GHG
benefits have presented results using a zero discount rate.\298\
However, some of the climate change literature supports using a higher
discount rate, as described in Section IX.C. We show the 7% discount
rate for illustrative purposes; however climate change benefit analyses
from global long-run growth models typically use discount rates well
under 7% for standard analysis.\299\ High discount rates imply very low
values for the future GHG emission impacts resulting from today's
actions on the welfare of future generations. Therefore, lower discount
rates such as 2-3% are considered more appropriate for discounting long
term climate change impacts.\300\
---------------------------------------------------------------------------
\298\ Searchinger et al., 2008.
\299\ Tol, 2005.
\300\ Newell and Pizer, 2003.
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In the analysis for this proposal we use a 2% discount rate to
assess the present value of GHG emissions changes which occur over a
100 year time frame. This discount rate is consistent with the Office
of Management and Budget (OMB) \301\ and EPA \302\ guidance and is one
of the discount rates that has been used in the literature to monetize
the impacts of climate change.\303\ EPA has considered this issue
previously, and after weighing the pros and cons of different values,
set forth a guidance document recommending using a range of consumption
based discount rates of 0.5-3%. OMB and EPA guidance on inter-
generational discounting suggests using a low but positive discount
rate if there are important inter-generational benefits and costs. In
selecting a 2% discount rate coupled with a 100 year emission stream
estimate, EPA would be recognizing the long term nature of the emission
impacts of biofuel production, the uncertainty in estimating these
emission impacts and their consequences plus the significance of nearer
term emission changes in avoiding future consequences. Other options
for intergenerational discounting have been discussed in the economic
literature, such as dealing with uncertainty by using a non-constant,
declining, or negative discount rate.\304\ Comments could consider how
discounting appropriately reflects the uneven emission of greenhouse
gases from biofuels over time, the uncertainty in predicting emissions
in more distant futures and the impacts these emissions could have on
climate change. Alternative approaches for inter-generational
discounting are described in Chapter 5.3 of the DRIA.
---------------------------------------------------------------------------
\301\ OMB Circular A-4, 2003 provides a range of 1-3% for
consumption based discount rates.
\302\ EPA Guidelines for Preparing Economic Analyses, 2000.
\303\ Tol (2005, 2007).
\304\ Newell and Pizer, 2003, Weitzman (1999, 2001), Nordhaus
(2008), Guo et al., (2006), Saez, C.A. and J.C. Requena,
``Reconciling sustainability and discounting in Cost-Benefit
Analysis: A methodological proposal'', Ecological Economics, 2007,
vol. 60, issue 4, pages 712-725.
---------------------------------------------------------------------------
Because we are considering not discounting GHG emissions and in
particular since the justifications for discounting physical emissions
are not as strong for shorter time periods, in Section VI.C.2, we also
present the GHG emissions reductions associated with biofuels using a
30 year time period and no discount rate. Using a zero percent or no
discount rate implies that all emission releases and uptakes during
this time period are valued equally. For a shorter time period such as
thirty years, we are relatively certain of the emission trends.
Furthermore, all of these emissions occur in a relatively short period
of time so their impact on climate change and the consequences of that
climate change could all be considered the same regardless of whether
those emissions occurred early or late in this 30-year time period.
We specifically invite comment on our use of a 2% discount rate
with a 100 year time period for analysis of lifecycle GHG emissions,
and our use of no discount rate in our analysis of GHG emissions over
30 years. We also invite comments on whether using physical science
metrics such as the actual quantities of climate forcing gasses in the
atmosphere, actual quantities of climate forcing gasses in the
atmosphere weighted by global warming potential (GWP), or cumulative
radiative forcing should be used to evaluate emissions over time.
Specifically, we seek comment on an approach for comparing GHG
emissions based on the time profile of the greenhouse gas emissions in
the atmosphere, and whether this approach would be consistent with the
legal definition of lifecycle GHG emissions in EISA. One such method is
the Fuel Warming Potential as outlined in a memo to the EPA from the
Union of Concerned Scientists which is available on the public docket
for this rulemaking.\305\ This approach is based on the ratio of the
cumulative radiative forcing between the biofuel and the gasoline case
over a specified time frame.
---------------------------------------------------------------------------
\305\ See Memo to EPA, Office of Transportation and Air Quality
from Union of Concerned Scientists, Re: Treatment of Time in Life
Cycle Accounting, February 18, 2009.
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The EISA definition of lifecycle GHG emissions stipulates that the
mass values for all greenhouse gas emissions shall be adjusted to
account for their relative GWP. We are proposing to use the standard
100-year GWP's published in the IPCC Second Assessment
Report.306 307 We invite comment on whether it is
appropriate to discount GWP-weighted emissions and how such discounting
might appropriately apply across the several greenhouse gases.
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\306\ See http://www.ipcc.ch/ipccreports/assessments-reports.htm.
\307\ O'Hare, Plevin, Martin, Jones, Kendal and Hopson; ``Proper
accounting for time increases crop-based biofuel's greenhouse gas
deficit versus petroleum''; Environmental Research Letters, 4 (2009)
024001.
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Furthermore, if alternative time periods for the production of
biofuels and the GHG impacts of biofuel production are considered as
discussed above, and the choice is made to discount GHG emissions, the
question that arises is: What discount rate or combination of discount
rates should be considered? For example, if ethanol production is
assumed to occur for 30 years and the GHG impacts are assumed to span
across 80-100 years, should a single discount rate be applied to the
emissions stream or alternative discount rates based upon the different
time frames? EPA is taking comment on whether and how to apply
discounting when different time frames between the production and long-
run GHG impacts are utilized to analysis biofuels. Specifically, EPA is
considering and requests comment on the option of using either no
discount rate or a 3% discount rate to assess those emissions that
occur during the relatively shorter time frame for biofuel use which
could phase out within 30 years as in our corn ethanol example and a 2%
discount rate over the reminder of the 100 years in assessing the
longer term GHG emissions impacts resulting from land use changes
related to biofuel production (including land reversion
considerations).
EPA is considering a range of discount rates including zero or no
discounting for reasons as described above and requests comments on the
appropriate discount rate to use when assessing the stream of GHG
emission changes that are likely to result from biofuel production and
use. Other
[[Page 25039]]
options for intergenerational discounting have been discussed in the
economic literature, such as dealing with uncertainty by using a non-
constant, declining, or negative discount rate.\308\ Comments could
consider how discounting appropriately reflects the uneven release of
greenhouse gases from biofuels over time, the uncertainty in predicting
emissions in more distant futures and the impacts these emissions could
have on climate change. Alternative approaches for inter-generational
discounting are described in Chapter 5.3 of the DRIA.
---------------------------------------------------------------------------
\308\ Newell and Pizer, 2003, Weitzman (1999, 2001), Nordhaus
(2008), Guo et al., (2006), Saez, C.A. and J.C. Requena,
``Reconciling sustainability and discounting in Cost-Benefit
Analysis: A methodological proposal'', Ecological Economics, 2007,
vol. 60, issue 4, pages 712-725.
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EPA recognizes that the time horizon for analysis and the treatment
of future emissions including the appropriateness of applying discount
factors are key factors in determining biofuel lifecycle GHG impacts;
therefore, we plan to organize an expert peer review of these issues
before the final rule.
c. Feedstock Transport
The GHG impacts of transporting corn from the field to the ethanol
facility and transporting the co-product DGs from the ethanol facility
to the point of use were included in this analysis. The GREET default
of truck transportation of 50 miles was used to represent corn
transportation from farm to plant. Transportation assumptions for DGs
transport were 14% shipped by rail 800 miles, 2% shipped by barge 520
miles, and 86% shipped by truck 50 miles. The percent shipped by mode
was from data provided by USDA and based on Association of American
Railroads, Army Corps of Engineers, Commodity Freight Statistics, and
industry estimates. The distances DGs were shipped were based on GREET
defaults for other commodities shipped by those transportation modes.
The GHG emissions from transport of corn and DGs are based on GREET
default emission factors for each type of vehicle including capacity,
fuel economy, and type of fuel used. Similar detailed analyses were
conducted for the transport of cellulosic biofuel feedstock and
biomass-based diesel feedstock.
As part of this rulemaking analysis we have conducted a more
detailed analysis of biofuel production locations and transportation
distances and modes of transport used in the criteria pollutant
emissions inventory calculations described in DRIA Chapter 1.6 and for
the cost analysis of this rule described in DRIA Chapter 4.2. Given the
timing of when the current analysis was completed we were not able to
incorporate this updated transportation information into our lifecycle
analysis but plan to do that for the final rule.
Furthermore, the transportation modes and distances assumed for
corn and DGs do not account for the secondary or indirect
transportation impacts. For example, decreases in exports might reduce
overall domestic agricultural commodity transport and emissions but
might increase transportation of commodities internationally. We plan
to consider these secondary transportation impacts in our final rule
analysis.
d. Processing
The GHG emissions estimates associated with the processing of
renewable fuels is dependent on a number of assumptions and varies
significantly based on a number of key variables. The ethanol yield
impacts the total amount of corn used and associated agricultural
sector GHG emissions. The amount of DGs and other co-products produced
will also impact the agricultural sector emissions in terms of being
used as a feed replacement. Finally the energy used by the ethanol
plant will result in GHG emissions, both from producing the fuel used
and through direct combustion emissions.
As mentioned above, in traditional lifecycle analyses, the energy
consumed and emissions generated by a renewable fuel plant must be
allocated not only to the renewable fuel, but also to each of the by-
products. For corn ethanol production, our analysis avoids the need to
allocate by accounting for the DGs and other co-products directly in
the FASOM and FAPRI agricultural sector modeling described above. DGs
are considered a partial replacement for corn and other animal feed and
thus reduce the need to make up for the corn production that went into
ethanol production. Since FASOM takes the benefits from the production
and use of DGs into account (e.g., displacing the need to grow
additional crops for feed and therefore reducing GHG emissions in the
agricultural sector), no further allocation was needed at the ethanol
plant and all plant emissions are accounted for here.
In terms of the energy used at renewable fuel facilities, there is
a lot of variation between plants based on the process type (e.g., wet
vs. dry milling) and the type of fuel used (e.g., coal vs. natural
gas). There can also be variation between the same type of plants using
the same fuel source based on the age of the plant and types of
processes included, etc. For our analysis we considered different
pathways for corn ethanol production. Our focus was to differentiate
between facilities based on the key differences between plants, namely
the type of plant and the type of fuel used. One other key difference
we modeled between plants was the treatment of the co-products DGs. One
of the main energy drivers of ethanol production is drying of the DGs.
Plants that are co-located with feedlots have the ability to provide
the co-product without drying. This has a big enough impact on overall
results that we defined a specific category for wet vs. dry co-product.
One additional factor that appears to have a significant impact on GHG
emissions is corn oil fractionation from DGs. Therefore, this category
is also broken out as a separate category in the following section. See
DRIA Chapter 1.4 for a discussion of corn oil fractionation.
Furthermore, as our analysis was based on a future timeframe, we
modeled future plant energy use to represent plants that would be built
to meet requirements of increased ethanol production, as opposed to
current or historic data on energy used in ethanol production. The
energy use at dry mill plants was based on ASPEN models developed by
USDA and updated to reflect changes in technology out to 2022 as
described in DRIA Chapter 4.1.
The GHG emissions from renewable fuel production are calculated by
multiplying the Btus of the different types of energy inputs by
emissions factors for combustion of those fuel sources. The emission
factors for the different fuel types are from GREET and are based
primarily on assumed carbon contents of the different process fuels.
The emissions from producing electricity are also taken from GREET and
represent average U.S. grid electricity production emissions. The
emissions from combustion of biomass fuel source are not assumed to
increase net atmospheric CO2 levels 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. Therefore, CO2 emissions from biomass
combustion as a process fuel source are not included in the lifecycle
GHG inventory of the ethanol plant.
e. Fuel Transport
Transportation and distribution of ethanol, biomass-based diesel,
petroleum diesel and gasoline were also included in this analysis based
on GREET defaults. The GREET defaults for
[[Page 25040]]
both ethanol and gasoline transport from plant/refinery to bulk
terminals were used. The GREET defaults for both ethanol and gasoline
distribution from the bulk terminal to the service station were also
used.
As with feedstock transport we have conducted a more detailed
analysis of fuel transport and distribution impacts for use in criteria
pollutant inventories (see DRIA Chapter 1.6) and for our cost analysis
described in DRIA Chapter 4.2. Due to the timing of this analysis we
were not able to incorporate the results in our proposed lifecycle
calculation but plan to do that for the final rule.
f. Tailpipe Combustion
Combustion CO2 emissions for ethanol, biomass-based
diesel, petroleum diesel and gasoline were based on the carbon content
of the fuel. However, over the full lifecycle of the fuel, 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. Net carbon fluxes from changes in biogenic
carbon reservoirs in wooded or crop lands are accounted for separately
in the land use change analysis as outlined in the agricultural sector
modeling above.
When calculating combustion GHG emissions, however, the methane and
N2O emitted during biomass-based fuels combustion are
included in the analysis. Unlike CO2 emissions, the
combustion of biomass-based fuels does result in net additions of
methane and N2O to the atmosphere. Therefore, combustion
methane and N2O emissions are included in the lifecycle GHG
emissions results for biomass-based fuels.
Combustion related methane and N2O emissions for both
biomass-based fuels and petroleum-based fuels are based on EPA MOVES
model results.
6. Petroleum Baseline
To establish the lifecycle greenhouse gas emissions associated with
the petroleum baseline against which the renewable fuels were compared,
we used an updated version of the GREET model. Lifecycle energy use and
associated emissions for petroleum-based fuels in GREET is calculated
based on an energy efficiency metric for the different processes
involved with petroleum-based fuels production. The energy efficiency
metric is a measure of how many Btus of input energy are needed to make
a Btu of product. GREET has assumptions on energy efficiency for
different finished petroleum products as well as for different types of
crude oil.
We are using the latest version of the GREET model for this
analysis (Version 1.8b) which includes recent updates to the energy
efficiencies of petroleum refining. To represent baseline petroleum
fuels we have used the 2005 estimates of actual gasoline and diesel
fuel used. For 2005, 86% of gasoline and 92% of diesel fuel was
produced domestically with the rest imported finished product. To
represent international production we assume the same GHG refinery
emissions from GREET as used domestically. We did not include indirect
land use impacts in assessing the lifecycle GHG performance of the 2005
baseline fuel pool as we believe these would insignificantly impact the
average performance assessment of the baseline. Additionally,
consistent with our assessment of energy security impacts, we did not
include as an indirect GHG impact the potential impact of maintaining a
military presence.
GREET also has assumptions on the mix of energy sources used to
provide the energy input, which determine GHG emissions. For example if
coal, natural gas, or purchased electricity is used as an energy
source. The GHG emissions associated with petroleum fuel production are
based on the emissions from producing and combusting the input energy
sources needed, like GHG emissions from using natural gas at the
petroleum refinery. Non-combustion GHG sources like fugitive methane
emissions are added in where applicable.
Based on the EISA requirements, we used the 2005 mix of crude as
the petroleum baseline. We developed emissions factors for those crude
types since they are not currently included in GREET. In 2005, 5% of
crude was Canadian tar sand, 1% was Venezuela extra heavy, and 23% was
heavy crude.
For this proposal, we are using the average GHG emissions
associated with the 2005 petroleum baseline, as required by EISA.
However, we recognize that an additional gallon of renewable fuel
replaces the marginal gallon of petroleum fuel. To the extent that the
marginal gallon is from oil sands or other types of crude oil that are
associated with higher than average GHG emissions, replacing these
fuels could have a larger GHG benefit. Conversely to the extent the
marginal gallon displaced is from imported gasoline produced from light
crude, replacing these fuels would have a smaller GHG benefit. We
solicit comment on whether--strictly for purposes of assessing the
benefits of the rule (and not for purposes of determining whether
certain renewable fuel pathways meet the GHG reduction thresholds set
forth in EISA), we should assess benefits based on a marginal
displacement approach and, if so, what assumptions we should use for
the marginal displacements.
In December 2008, the U.S. Department of Energy's National Energy
Technology Laboratory (NETL) released a report that estimates the
average lifecycle GHG emissions from petroleum-based fuels sold or
distributed in 2005.\309\ The estimates in the report are based on a
slightly different methodology than EPA's analysis of lifecycle GHG
emissions for the petroleum baseline. The NETL report is available on
the docket for this rulemaking. We invite comments on whether NETL's
analysis has significant implications for how EPA is estimating
petroleum baseline lifecycle GHG emissions.
---------------------------------------------------------------------------
\309\ DOE/NETL. 2008. Development of Baseline Data and Analysis
of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels.
DOE/NETL-2009/1346.
---------------------------------------------------------------------------
7. Energy Sector Indirect Impacts
Increased demand for natural gas to power corn ethanol plants could
have additional impacts on the U.S. energy sector. As demand for
natural gas increases, the use of natural gas in other sectors (e.g.,
electric generation) could decrease. For this analysis, we are using
the NEMS model to project the secondary or indirect impacts on the
energy sector. However, we were not able to include this analysis in
the GHG emissions estimates presented in this proposal. We hope to have
this analysis for the final rule. Additional details on the methodology
are included in the DRIA Chapter 2, and we invite comments on this
approach.
We are assuming, for the proposal, that a gallon of renewable fuel
replaces an energy equivalent gallon of petroleum fuel. This analysis
presumes that petroleum-based fuels as they are currently produced will
continue to be used for transportation fuels and will be replaced on a
Btu for Btu basis. Many factors could affect this assumption including
advances in petroleum fuel technology, availability of other fossil
fuels for transportation use, and of course the supply and cost of
petroleum. We have not tried to analyze these potential impacts in this
rule. However we invite comment on such an approach.
We have also not assessed whether expanded use of biofuels in the
U.S.
[[Page 25041]]
will impact the energy markets in other countries. For example,
reducing demand for petroleum-based fuel in the U.S. may reduce
worldwide petroleum prices and impact the use of petroleum in other
countries. We invite comment on how best to assess these potential
impacts and will attempt to do so for the final rule.
C. Fuel Specific GHG Emissions Estimates
While the results presented in this section represent the most up-
to-date information currently available, this analysis is part of an
ongoing process. Because lifecycle analysis is a new part of the RFS
program, in addition to the formal comment period on the proposed rule,
EPA is making multiple efforts to solicit public and expert feedback on
our proposed approach. As discussed in Section XI, EPA plans to hold a
public workshop focused specifically on lifecycle analysis during the
comment period to assure full understanding of the analyses conducted,
the issues addressed and options that should be considered. We expect
that this workshop will allow the most thoughtful and useful comments
to this proposal and assure the best methodology and assumptions are
used for calculating GHG emissions impacts of fuels for the final rule.
Additionally we will conduct peer-reviews of key components of our
analysis. As part of ongoing analysis for the final rule, EPA will seek
peer review of: Our use of satellite data to project future land use
changes; the land conversion GHG emissions factors estimated by
Winrock; our estimates of GHG emissions from foreign crop production;
methods to account for the variable timing of GHG emissions; and how
models are used together to provide overall lifecycle GHG estimates.
In addition to the refinements to the methodology that we plan to
undertake for the final rule, we also intend to update our results
periodically. EPA recognizes that the state of the science for
lifecycle GHG analysis will continue to evolve over time as new data
and modeling techniques become available and as there are improvements
in agricultural and renewable fuel production practices as well as new
feedstocks. We invite comments on the appropriate amount of time for
periodic review of the lifecycle assessment methodology, but we propose
that performing an update of the methodology every 3-5 years would be
appropriate. We would expect the first update to this analysis would
occur closer to 3 years. This timeframe would allow us to undergo a
formal review process after the final rule to ensure that this
methodology takes into account the most state-of-the-art science and
reflects the input of appropriate experts in this field. However, any
change in lifecycle methodology as contemplated here would not affect
the eligibility of biofuels produced at facilities covered by the
grandfathering provisions of EISA at section 211(o)(4)(g).
1. Greenhouse Gas Emissions Reductions Relative to the 2005 Petroleum
Baseline
In this section we present detailed lifecycle GHG results for
several specific biofuels representing a range biofuel pathways. This
section also includes the results of sensitivity analysis for key
variables. The sensitivity of the time period and discount rate are
discussed below. In the rest of this section we focus on two sets of
lifecycle GHG results. One set of results that uses a 100 year time
period and 2% discount rate and a parallel set of results using a 30
year time period and a 0% discount rate. In Section IV.C.2 which
follows, we also present the results for some additional combinations
of time horizon for assessing GHG emission changes as well as assuming
other discount rates. Additional pathways, not included in the results
presented in this section, distinguishing other combinations of
feedstock and processing technologies have been evaluated. These
additional pathways are described in detail in the DRIA and are
included in these proposed regulations.
a. Corn Ethanol
Table VI.C.1-1 presents the breakout of the net present value of
lifecycle GHG emissions per million British thermal unit (mmbtu) of
corn ethanol and gasoline. The results are broken out by lifecycle
stage. Values are shown for a standard dry mill corn ethanol plant in
2022 using natural gas for process energy and drying the co-product of
distillers grains (DGs). Results indicate where the major contributions
of GHG emissions are across the fuel lifecycle. Fuel processing and
indirect land use change are the main contributors to corn ethanol
lifecycle GHG emissions. Net domestic and international agricultural
impacts (w/o land use change) include direct and indirect impacts, such
as reductions in livestock enteric fermentation.
---------------------------------------------------------------------------
\310\ For this proposal, our preliminary analysis suggests land
use impacts of petroleum production for the fuels used in the U.S.
in 2005 would not have an appreciable impact on the 2005 baseline
GHG emissions assessment. However, we expect to more carefully
consider potential land use impacts of petroleum-based fuel
production for the final rule and invite comment and information
that would support such an analysis.
\311\ 2005 petroleum baseline fuel production includes crude oil
extraction, transportation, refining, and transport of finished
product.
\312\ Ethanol tailpipe emissions include CH4 and
N2O emissions but not CO2 emissions as these
are assumed to be offset by feedstock carbon uptake.
Table VI.C.1-1--Absolute Lifecycle GHG Emissions for Corn Ethanol and the 2005 Petroleum Baseline
[CO2-eq/mmBtu]
----------------------------------------------------------------------------------------------------------------
Natural gas Natural gas
2005 Gasoline dry mill with 2005 Gasoline dry mill with
baseline dry DGs baseline dry DGs
----------------------------------------------------------------------------------------------------------------
Lifecycle Stage 100 yr 2%
30 yr 0%
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).. N/A -499,029 N/A -347,365
Net International Agriculture (w/o land use N/A 452,118 N/A 314,711
change)........................................
Domestic Land Use Change........................ N/A 79,547 N/A 92,575
International Land Use Change................... N/A \310\ 1,911,391 N/A 1,910,822
Fuel Production \311\........................... 823,262 1,404,083 573,058 977,358
Fuel and Feedstock Transport.................... (see footnote 174,327 .............. 121,346
321)
Tailpipe Emissions \312\........................ 3,417,311 37,927 2,378,800 26,400
�������������������������������������������������
Net Total Emissions......................... 4,240,674 3,560,365 2,951,858 3,095,846
----------------------------------------------------------------------------------------------------------------
[[Page 25042]]
Table VI.C.1-1 demonstrates the importance of the discount rate and
time period analyzed as well as the importance of significance of
including GHG emissions from international land use changes. Assuming
100 years of corn ethanol produced in a basic dry mill ethanol
production facility and using a 2% discount rate results in corn
ethanol having a 16% reduction in GHG emissions compared to the 2005
baseline gasoline assumed to be replaced. In contrast, assuming 30
years of corn ethanol production and use and no discounting of the GHG
emission impacts results in predicting that corn ethanol will have a 5%
increase in GHG emissions compared to petroleum gasoline.
As discussed in Section VI.B.2.a, EPA's interpretation of the EISA
statute compels us to include significant indirect emission impacts
including those due to land use changes in other countries. The data in
Table VI.C.1-1 indicate that excluding the international land use
change would result in corn ethanol having an approximately 60%
reduction in lifecycle GHG emissions compared to petroleum gasoline
regardless of the timing or discount rate used.\313\
---------------------------------------------------------------------------
\313\ The treatment of emissions over time is not critical if
international land use change emissions are excluded because the
results without land use change are consistent over time. Therefore
the overall lifecycle GHG results do not vary with time or discount
rate assumptions.
---------------------------------------------------------------------------
In Table VI.C.1-1, we project a standard dry mill ethanol plant in
2022 using corn as its feedstock, using natural gas for process energy,
and drying the co-product of distillers grains (DGs). Different corn
ethanol production technologies will have different lifecycle GHG
results. For example, due to its high carbon content, using coal as the
process energy source significantly worsens the lifecycle GHG impact of
ethanol produced at such a facility. On the other hand, replacing
natural gas with renewable biomass as the process energy source greatly
improves the GHG assessment.
Other technology options are available to improve the efficiency of
ethanol facilities. Table VI.C.1-2 shows the impact that different corn
ethanol production process pathways will have on the overall lifecycle
GHG results. Table VI.C.2-2 shows that currently available technologies
could be applied to corn ethanol plants to reduce their net GHG
emissions.
For example, a combined heat and power (CHP) configuration, used in
combination with corn oil fractionation, would result in a GHG
emissions reduction of 27% relative to the 2005 petroleum baseline over
100 years using a 2% discount rate, and a 6% reduction over 30 years
with no discounting. In addition, advanced technologies such as
membrane separation and raw starch hydrolysis could improve the
emissions associated with corn ethanol production even more
substantially. Combining all of these technologies in a state-of-the-
art natural gas powered corn ethanol facility would produce ethanol
that has approximately 35% less lifecycle GHG emissions than an energy
equivalent amount of baseline gasoline displaced over 100 years using a
2% discount rate and, by comparison a 14% reduction when accounting for
30 years of emission changes but applying no discounting. Details on
these different technologies are included in the DRIA Chapter 1.5.
Table VI.C.1-2 also shows that the choice of drying DGs can have a
significant impact on the GHG emissions associated with an ethanol
plan, since drying the ethanol byproduct is an energy intensive
process. However, wet DGs are only suitable where a local market is
available such as a dairy farm or cattle feedlot, since wet DGs are
highly perishable.
Table VI.C.1-2--Lifecycle GHG Emissions Changes for Various Corn Ethanol
Pathways in 2022 Relative to the 2005 Petroleum Baseline
------------------------------------------------------------------------
Percent change
from 2005 Percent change
Corn ethanol production plant type petroleum from 2005
baseline (100 baseline (30
yr 2%) yr 0%)
------------------------------------------------------------------------
Natural Gas Dry Mill with dry DGs....... -16 +5
Natural Gas Dry Mill with dry DGs and -19 +2
CHP....................................
Natural Gas Dry Mill with dry DGs, CHP, -27 -6
and Corn Oil Fractionation.............
Natural Gas Dry Mill with dry DGs, CHP, -30 -10
Corn Oil Fractionation, and Membrane
Separation.............................
Natural Gas Dry Mill with dry DGs, CHP, -35 -14
Corn Oil Fractionation, Membrane
Separation, and Raw Starch Hydrolysis..
Natural Gas Dry Mill with wet DGs....... -27 -6
Natural Gas Dry Mill with wet DGs and -30 -9
CHP....................................
Natural Gas Dry Mill with wet DGs, CHP, -33 -12
and Corn Oil Fractionation.............
Natural Gas Dry Mill with wet DGs, CHP, -36 -15
Corn Oil Fractionation, and Membrane
Separation.............................
Natural Gas Dry Mill with wet DGs, CHP, -39 -18
Corn Oil Fractionation, Membrane
Separation, and Raw Starch Hydrolysis..
Coal Fired Dry Mill with dry DGs........ +13 +34
Coal Fired Dry Mill with dry DGs and CHP +10 +31
Coal Fired Dry Mill with dry DGs, CHP, -5 +15
and Corn Oil Fractionation.............
Coal Fired Dry Mill with dry DGs, CHP, -13 +8
Corn Oil Fractionation, and Membrane
Separation.............................
Coal Fired Dry Mill with dry DGs, CHP, -21 -1
Corn Oil Fractionation, Membrane
Separation, and Raw Starch Hydrolysis..
Coal Fired Dry Mill with wet DGs........ -9 +12
Coal Fired Dry Mill with wet DGs and CHP -11 +10
Coal Fired Dry Mill with wet DGs, CHP, -17 +3
and Corn Oil Fractionation.............
Coal Fired Dry Mill with wet DGs, CHP, -25 -4
Corn Oil Fractionation, and Membrane
Separation.............................
Coal Fired Dry Mill with wet DGs, CHP, -30 -9
Corn Oil Fractionation, Membrane
Separation, and Raw Starch Hydrolysis..
Biomass Fired Dry Mill with dry DGs..... -39 -18
Biomass Fired Dry Mill with wet DGs..... -40 -19
Natural Gas Fired Wet Mill.............. -7 +14
[[Page 25043]]
Coal Fired Wet Mill..................... +20 +41
Biomass Fired Wet Mill.................. -47 -26
------------------------------------------------------------------------
As described in Sections VI.A and VI.B, there are a number of
parameters and modeling assumptions that could impact the overall
renewable fuel GHG results. The estimates in Table VI.C.1-2 are based
on the GHG emissions for a specific change in volumes analyzed in 2022
(12.3 to 15 Bgal). These volumes represent the change in corn ethanol
production that would occur in 2022 without and then with EISA mandates
in place. The GHG impact is then normalized to a per gallon or Btu
basis in relation to gasoline. These values are used to represent every
gallon of corn ethanol produced throughout the program.
There are several important implications associated with this
methodology. First, this analysis focuses on the average impact of an
increase in fuel produced using a technology pathway and does not
distinguish the emission performance between biofuel production plants
using the same basic production technology and type of feedstock. Thus
it does not account for any incremental differences in facility design
or operation which may affect the lifecycle GHG performance at that
facility. Second, by focusing on 2022, this analysis does not track how
biofuel GHG emission performance may change over time between now and
2022. Third, the results presented here are based on the GHG impacts of
the volumes analyzed.
For this proposal, we believe that using the emissions assessment
from a typical 2022 facility for each major technology pathway captures
the appropriate level of detail needed to determine whether a
particular biofuel meets the threshold requirements in EISA. To address
whether the GHG emissions vary significantly over time, we also
calculated corn ethanol lifecycle GHG emissions estimates in 2012 and
2017. As shown in Table VI.C.1-3, corn ethanol's lifecycle GHG
emissions reductions are fairly consistent regardless of which base
year is analyzed. This may be due to countervailing forces that
stabilize land use change emissions over the period of our analysis.
Crop yields increase over time (therefore reducing land use pressure),
but there is also increasing production of other renewable fuels that
require land for feedstock production (therefore increasing land use
pressure). Although we are proposing to use 2022 as the base year for
our lifecycle GHG emissions estimates, we invite comments on this
approach.
Table VI.C.1-3--Corn Ethanol Lifecycle GHG Emissions Changes in 2012,
2017, and 2022
------------------------------------------------------------------------
Percent change Percent change
from 2005 from 2005
Scenario Description petroleum petroleum
baseline (100 baseline (30
yr 2%) yr 0%)
------------------------------------------------------------------------
Corn Ethanol Natural Gas Dry Mill in -16 -3
2012 with dry DGs......................
Corn Ethanol Natural Gas Dry Mill in -13 +9
2017 with dry DGs......................
Corn Ethanol Natural Gas Dry Mill in -16 +5
2022 with dry DGs......................
------------------------------------------------------------------------
We also tested the impact of analyzing a larger change in corn
ethanol volumes on the GHG emissions estimates. Table VI.C.1-4 shows
the sensitivity of our analysis to the volume changes analyzed. Based
on this scenario, the GHG emissions estimates associated with a larger
change (6.3 Bgal) in corn ethanol volumes (8.7 Bgal to 15 Bgal) results
in lower GHG emission reductions. Additional details on these
sensitivity analyses are included in the DRIA Chapter 2.
Table VI.C.1-4--Corn Ethanol Lifecycle GHG Emissions Changes Associated
With Different Volume Changes
------------------------------------------------------------------------
Percent Change Percent Change
from 2005 from 2005
Scenario Description Petroleum Petroleum
Baseline (100 Baseline (30
yr 2%) yr 0%)
------------------------------------------------------------------------
Corn Ethanol Natural Gas Dry Mill in -16 +5
2022 with dry DGs; 2.7 Bgal change in
corn ethanol volumes...................
Corn Ethanol Natural Gas Dry Mill in -6 +14
2022 with dry DGs; 6.3 Bgal change in
corn ethanol volumes...................
------------------------------------------------------------------------
The results presented in previous tables assume that managed
pasture (i.e., land actively used for livestock grazing) converted from
pasture to cropland would be replaced with new pasture in other areas.
The area of
[[Page 25044]]
managed pasture converted to cropland was estimated using satellite
data from Winrock and land cover data from GTAP. As a sensitivity
analysis, we also analyzed a scenario in which none of the pastureland
converted to cropland would be replaced if, for example, livestock
production could be more intensively developed on the remaining pasture
(see first row in Table VI.C.1-5). Similarly, we also calculated
results assuming that all pasture acres would be replaced (second row
in Table VI.C.1-5). Finally, the third row of Table VI.C.1-5 includes
lifecycle GHG results assuming that all of the land converted to
cropland would come from pasture and that none of that pasture would be
replaced, which is counter to the land use trends identified by the
Winrock satellite data. As can be seen, the assumption of pastureland
replacement can have a significant effect on the results. We ask for
comment on the best assumptions to be made when considering the need to
replace pasture that has been converted to crop production. We note
that the best decision on pasture land replacement may vary by country
or region due to such factors as the current intensity of use of
pasture land as well as trends in demand for pasture. DRIA Chapter 2
includes more details about the treatment of pasture conversion, and
sensitivity analysis of the types land use changes induced by corn
ethanol production.
Table VI.C.1-5--Corn Ethanol Lifecycle GHG Emissions Changes Associated
with Different Assumptions on Land Use Changes
------------------------------------------------------------------------
Percent Change Percent Change
from 2005 from 2005
Scenario Description Petroleum Petroleum
Baseline (100 Baseline (30
yr 2%) yr 0%)
------------------------------------------------------------------------
Corn Ethanol Natural Gas Dry Mill in -34 -19
2022 with dry DGs; 0% pastureland
replaced...............................
Corn Ethanol Natural Gas Dry Mill in -2 +24
2022 with dry DGs; 100% pastureland
replaced...............................
Corn Ethanol Natural Gas Dry Mill in -48 -38
2022 with dry DGs; grassland only
conversion and 0% pastureland replaced.
------------------------------------------------------------------------
DRIA Chapter 2 includes results for additional sensitivity analysis
of corn ethanol lifecycle GHG emissions. We also intend to conduct
additional sensitivity analysis for the final rule. We invite comment
on these assumptions.
b. Imported Ethanol
Table VI.C.1-6 presents the breakout of lifecycle GHG emissions for
sugarcane ethanol compared to a 2005 petroleum baseline under different
discount rate and time horizon scenarios and land use assumptions. This
assessment was based on applying the same methodology as for other
biofuels including the assessment of both direct and indirect impacts
using the combination of FASOM, FAPRI and Winrock modeling results.
Virtually all the ethanol from sugarcane is expected to be imported
from Brazilian production. Applying the proposed FAPRI/Winrock
methodology to sugarcane ethanol production in Brazil predicts a large
increase in new acres planted, which has a relatively large impact on
overall GHG emissions. The impact is from both new sugarcane production
acres in Brazil resulting in land use change but also reduced commodity
exports from Brazil resulting in land use change in other countries.
The proposed FAPRI/Winrock methodology predicts that new crop
acreage is converted from a range of land types. In contrast, some
studies suggest that sugarcane ethanol production can increase in
Brazil by relying on existing excess pasture lands and will not
significantly impact other land types.\314\ Table VI.C.1-6 provides the
range of lifecycle GHG emission reduction results under these different
assumptions of type conversion patterns. As a sensitivity analysis,
shows results for a scenario where none of the grassland converted to
cropland in Brazil would be replaced if, for example, livestock
production could be more intensively developed on the remaining pasture
(see second row in Table VI.C.1-6). The third row of Table VI.C.1-6
includes lifecycle GHG results assuming that in Brazil all of the land
converted to cropland would come from grassland and that none of that
grassland would be replaced. As can be seen in the table, the
assumption of pastureland replacement can have an important effect on
the results. DRIA Chapter 2 includes more details about the treatment
of pasture conversion, and sensitivity analysis of the types land use
changes induced by sugarcane ethanol production.
---------------------------------------------------------------------------
\314\ Goldemberg, J.; Coelho, ST.; Guardabassi, PM. The
sustainability of ethanol production from sugarcane. Energy Policy.
2008. doi:10.1016/j.enpol.2008.02.028.
Table VI.C.1-6--Sugarcane Ethanol GHG Emission Changes Under Varied Land
Use Assumptions and Varied Discount Rates and Time Horizons Relative to
2005 Petroleum Baseline
------------------------------------------------------------------------
Land Use Change Scenario Description (100 yr 2%) (30 yr 0%)
------------------------------------------------------------------------
FAPRI/Winrock estimate with managed -44 -26
pasture replacement....................
FAPRI/Winrock estimate with no pasture -59 -45
replacement in Brazil..................
Only grassland conversion in Brazil and -64 -52
no pasture replacement in Brazil.......
------------------------------------------------------------------------
We are aware that recent land use enforcement policies in Brazil
may shift cropland expansion patterns (see also Section VI.B.5.b.iii).
We seek comment on both pasture conversion patterns and Brazil land use
enforcement policy impacts. We are conducting more detailed economic
modeling of the Brazilian agricultural sector by state for inclusion in
FAPRI to address pasture, enforcement and other assumptions for the
final rule. State level production data could be used in conjunction
with Winrock's state level satellite data, which may substantially
change the
[[Page 25045]]
estimates of the location and type of land being converted in Brazil
for the final rule.
We have also assumed that sugarcane ethanol production relies on
burning bagasse as an energy source and that the process produces
excess electricity. We factor in credits from this excess electricity
based on offsetting the Brazilian electricity grid. As Brazil
implements limits on field burning of bagasse there may be additional
bagasse used at sugarcane ethanol plants and additional electricity
production. We plan to look at this further for the final rule
analysis.
c. Cellulosic Ethanol
Given that commercially-viable cellulosic ethanol production is not
yet a reality, analysis of this pathway relies upon significant
assumptions regarding the development of production technologies. As
described in the previous section, our analysis assumed corn stover
required no international land use changes, since corn stover does not
compete with other crops for acreage in the U.S. Therefore, using corn
stover as a feedstock for cellulosic biofuel production would not have
an impact on U.S. exports. We assumed some of the nutrients would have
to be replaced through higher fertilizer rates on acres where stover is
removed; however, increased stover removal was also associated with
higher rates of reduced tillage or no tillage practices which results
in soil carbon increase. See Section IX.A for details. In addition,
cellulosic ethanol was assumed to be produced using the biochemical
process which is expected to produce more electricity from the lignin
in the feedstock than is required to power the ethanol plant, so excess
electricity can be sold back to the grid. See DRIA Chapter 2 for
additional details. This electricity provides a GHG benefit, which
results in GHG emissions reductions from fuel production as shown in
Table VI.C.1-7.
Table VI.C.1-7--Absolute Lifecycle GHG Emissions for Corn Stover Cellulosic Ethanol and the 2005 Petroleum
Baseline
[CO2-eq/mmBtu]
----------------------------------------------------------------------------------------------------------------
Corn stover Corn stover
ethanol ethanol
2005 (selling 2005 (selling
Petroleum excess Petroleum excess
baseline electricity to baseline electricity to
grid) grid)
----------------------------------------------------------------------------------------------------------------
Lifecycle Stage (100 yr 2%)
(30 yr 0%)
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).. .............. 178,862 N/A 124,503
Net International Agriculture (w/o land use .............. 0 N/A ..............
change)........................................
Domestic Land Use Change........................ .............. -78,448 N/A -91,925
International Land Use Change................... .............. 0 N/A 0
Fuel Production................................. 823,262 -875,424 573,058 -609,367
Fuel and Feedstock Transport.................... .............. 107,214 .............. 74,629
Tailpipe Emissions.............................. 3,417,311 37,927 2,378,800 26,400
---------------------------------------------------------------
Net Total Emissions......................... 4,240,674 -629,870 2,951,858 -475,130
----------------------------------------------------------------------------------------------------------------
Although switchgrass must compete with other crops for land in the
U.S., average switchgrass ethanol yields are on average higher than
corn ethanol yields (approximately 580 gallons/acre compared to 480
gallons/acre). Therefore, switchgrass would need approximately 20% less
land to produce the same amount of ethanol compared to corn. In
addition, FASOM predicts that switchgrass would generally be grown on
more marginally productive land. Since switchgrass is not projected to
displace crop acres with high yields, new switchgrass acres generally
would not have a large impact on exports. Therefore, the international
land use change impacts are modest. Like cellulosic ethanol from corn
stover, switchgrass ethanol is also assumed to produce excess
electricity that can be sold to the grid, therefore switchgrass
cellulosic ethanol results in relatively large lifecycle GHG reductions
compared to the replaced petroleum gasoline as shown in Table VI.C.1-8.
Table VI.C.1-8--Absolute GHG Emissions for Switchgrass Cellulosic Ethanol and the 2005 Petroleum Baseline
[CO2-eq/mmBtu]
----------------------------------------------------------------------------------------------------------------
Switchgrass Switchgrass
ethanol ethanol
2005 (selling 2005 (selling
Petroleum excess Petroleum excess
baseline electricity to baseline electricity to
grid) grid)
----------------------------------------------------------------------------------------------------------------
Lifecycle Stage (100 yr 2%)
(30 yr 0%)
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).. .............. -470,620 .............. -327,590
Net International Agriculture (w/o land use .............. -356,712 .............. -248,301
change)........................................
Domestic Land Use Change........................ .............. -65,318 .............. -76,015
International Land Use Change................... .............. 423,097 .............. 424,094
Fuel Production................................. 823,262 -874,599 573,058 -608,793
Fuel and Feedstock Transport.................... .............. 136,663 .............. 95,129
Tailpipe Emissions.............................. 3,417,311 37,927 2,378,800 26,400
---------------------------------------------------------------
[[Page 25046]]
Net Total Emissions......................... 4,240,674 -1,169,561 2,951,858 -715,076
----------------------------------------------------------------------------------------------------------------
Cellulosic ethanol does not have nearly as significant an impact on
land use as other biofuels, therefore we did not calculate sensitivity
impacts of, for example, assuming full replacement of pasture versus no
pasture replacement which could be important in the lifecycle GHG
assessment of other biofuels. As the land use issue is not critical for
the cellulosic feedstock fuels in the scenarios we analyzed, the impact
of timing and discount rates also do not have a significant impact on
the overall results for cellulosic ethanol. Both of the cellulosic
ethanol pathways we examined, switchgrass and corn stover using
enzymatic processing, reduced lifecycle GHG emissions by significantly
more than the 60% threshold for cellulosic biofuel. Table VI.C.1-9
summarizes the lifecycle GHG results for cellulosic ethanol fuel
pathways.
Table VI.C.1-9--Cellulosic Ethanol GHG Emission Changes From Different
Feedstocks and Varied Discount Rates and Time Horizons Relative to 2005
Petroleum Baseline
[In percent]
------------------------------------------------------------------------
Assumption--feedstock type (100 yr 2%) (30 yr 0%)
------------------------------------------------------------------------
Corn Stover....................... -115 -117
Switchgrass....................... -128 -121
------------------------------------------------------------------------
d. Biodiesel
EPA's modeling predicts that soybean-based biodiesel production has
a large land use impact for two major reasons. Soybean biodiesel has a
relatively low gallon per acre yield (approximately 65 gal/acre for
soybean biodiesel versus 480 gal/acre for corn ethanol). Thus, the
impact of any land-use change tends to be magnified with soybean
biodiesel. Even when the higher Btu value of biodiesel is taken into
consideration, Btu/acre yields are still significantly lower for
biodiesel than for ethanol (approximately 97 gal/acre ethanol
equivalent). Furthermore, our analysis suggests that due to high world
wide demand for soybeans for food, cooking and other non-biofuel uses,
soybean and other edible oils used for biofuel are generally replaced
by production in other countries including production in tropical
climates where the GHG emissions released per acre of converted land
are highest. This indicates that soy-based biodiesel lifecycle GHG
emissions could be greatly reduced with the adoption of policies and
agricultural practices that limit the amount of tropical deforestation
induced by soy-based biodiesel production. DRIA Chapter 2 includes
sensitivity analyses about the types of land converted to crops as a
result of soy-based biodiesel production. Table VI.C.1-10 presents the
breakout of the absolute lifecycle GHG emissions for soybean biodiesel
and the petroleum diesel fuel baseline by lifecycle stage.
Table VI.C.1-10--Absolute Lifecycle GHG Emissions for Soybean Biodiesel and the 2005 Petroleum Baseline
[CO2-eq/mmBtu]
----------------------------------------------------------------------------------------------------------------
2005 Petroleum Soybean 2005 Petroleum Soybean
baseline biodiesel baseline biodiesel
----------------------------------------------------------------------------------------------------------------
Lifecycle Stage (100 yr 2%)
(30 yr 0%)
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).. .............. -423,206 .............. -294,586
Net International Agriculture (w/o land use .............. 195,304 .............. 135,948
change)........................................
Domestic Land Use Change........................ .............. -8,980 .............. -10,451
International Land Use Change................... .............. 2,474,074 .............. 2,469,574
Fuel Production................................. 749,132 838,490 521,458 583,658
Fuel and Feedstock Transport.................... .............. 149,258 .............. 103,896
Tailpipe Emissions.............................. 3,424,635 30,169 2,383,828 21,000
---------------------------------------------------------------
Net Total Emissions......................... 4,173,768 3,255,109 2,905,286 3,009,039
----------------------------------------------------------------------------------------------------------------
Our analysis is based on a change in biodiesel volumes from 0.4
Bgal to 0.7 Bgal. Similar to the analysis we conducted for corn-
ethanol, we plan to run a sensitivity analysis on the impact of using
different volumes for the final rule.
[[Page 25047]]
As discussed in Section VI.B.2.a, EPA's interpretation of the EISA
statute compels us to include significant indirect emission impacts
including those due to land use changes in other countries. The data in
Table VI.C.1-10 indicate that excluding the international land use
change would result in soy-based biodiesel having an approximately 80%
reduction in lifecycle GHG emissions compared to petroleum gasoline
regardless of the timing or discount rate used. The treatment of
emissions over time is not critical if international land use change
emissions are excluded because the results without land use change are
consistent over time. Therefore the overall lifecycle GHG results do
not vary with time or discount rate assumptions.
In contrast, GHG emissions from waste oil and greases are assumed
to have no land use impacts. We assumed any land use change was
attributed to the original use of the feedstock, for example, soy oil
was produced for the purpose of using for cooking and the land required
to produce this cooking oil is properly attributed to that use.
Gathering and re-using the left over waste cooking oil would have no
additional land use impact. This lack of land use impact greatly
influences the lifecycle GHG analysis. Table VI.C.1-11 presents the
breakout of the absolute lifecycle GHG emissions for waste grease
biodiesel and the petroleum diesel fuel baseline by lifecycle stage.
Table VI.C.1-11--Absolute Lifecycle GHG Emissions for Waste Grease Biodiesel and the 2005 Petroleum Baseline
[CO2-eq/mmBtu]
----------------------------------------------------------------------------------------------------------------
2005 2005
Petroleum Waste grease Petroleum Waste grease
baseline biodiesel baseline biodiesel
----------------------------------------------------------------------------------------------------------------
Lifecycle Stage (100 yr 2%)
(30 yr 0%)
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).. .............. 0 .............. 0
Net International Agriculture (w/o land use .............. 0 .............. 0
change)........................................
Domestic Land Use Change........................ .............. 0 .............. 0
International Land Use Change................... .............. 0 .............. 0
Fuel Production................................. 749,132 658,198 521,458 458,160
Fuel and Feedstock Transport.................... .............. 149,258 .............. 103,896
Tailpipe Emissions.............................. 3,424,635 30,169 2,383,828 21,000
---------------------------------------------------------------
Net Total Emissions......................... 4,173,768 837,626 2,905,286 583,056
----------------------------------------------------------------------------------------------------------------
Table VI.C.1-12 summarizes the lifecycle GHG results for biodiesel
fuel pathways. As the waste grease biodiesel is not assumed to have any
land use impact the choice of timing or discount rate does not impact
the waste grease biodiesel results. However, as the soybean biodiesel
is found to have a large land use impact the choice of timing and
discount rate has a big impact on the soybean biodiesel results.
Table VI.C.1-12--Biodiesel Lifecycle GHG Emission Changes From different
Feedstocks and Varied Discount Rates and Time Horizons Relative to 2005
Petroleum Baseline
------------------------------------------------------------------------
Assumption--feedstock type (100 yr 2%) (30 yr 0%)
------------------------------------------------------------------------
Soybean........................... -22% +4%
Waste Grease...................... -80% -80%
------------------------------------------------------------------------
Table VI.C.1-13 shows the sensitivity of our assessment for soy oil
biodiesel assuming 100% of the grassland converted to cropland is
replaced compared to an assumption that none of this grassland is
replaced for livestock grazing. DRIA Section 2.8.2.4 provides more
information about sensitivity analysis for the pasture replacement
assumptions.
Table VI.C.1-13--Soy-Based Biodiesel GHG Emission Changes Under Varied
Land Use Assumptions and Varied Discount Rates and Time Horizons
Relative to 2005 Petroleum Baseline
------------------------------------------------------------------------
Assumption--land types available
for conversion (100 yr 2%) (30 yr 0%)
------------------------------------------------------------------------
100% Pasture Replacement.......... -4% +27%
No Pasture Replacement............ -45% -27%
------------------------------------------------------------------------
2. Treatment of GHG Emissions Over Time
As described in Section VI.B.5, changes in indirect land use
associated with increased biofuel production result in GHG emissions
increases that accumulate over a long time period. Since there is a
large release of carbon in the first year of land conversion, it can
take many years for the benefits of the biofuel to make up for these
early carbon emissions, depending on the specific biofuel in question.
Table VI.C.2-1 contains the payback period associated with several
types of biofuels and fuel production pathways. A payback period of 0
indicates that these pathways do not have land use change impacts and
therefore reduce emissions in the first year that they are produced.
Assessments are made in comparison to
[[Page 25048]]
the baseline transportation fuel used in 2005 in the U.S. as mandated
by EISA. The percent reduction goal is the lifecycle GHG emissions of
the biofuel compared to the baseline petroleum fuel it is replacing.
Table VI.C.2-1--Payback Period
[in years]
----------------------------------------------------------------------------------------------------------------
Payback period (years)
---------------------------------------------------------------
Fuel type Reduction Reduction Reduction Reduction
goal: 0% goal: 20% goal: 50% goal: 60%
----------------------------------------------------------------------------------------------------------------
Corn Ethanol 2022 Base Dry Mill NG \315\........ 33 54 \316\ N/A N/A
Corn Ethanol 2022 Best Case Dry Mill NG \317\... 23 31 N/A N/A
Corn Ethanol 2022 Base Dry Mill Coal \318\...... 75 >100 N/A N/A
Corn Ethanol 2022 Base Dry Mill Biomass \319\... 22 31 N/A N/A
Soybean Biodiesel............................... 32 46 105 N/A
Waste Grease Biodiesel.......................... 0 0 0 N/A
Sugarcane Ethanol............................... 18 26 61 N/A
Switchgrass Ethanol............................. 3 3 4 5
Corn Stover Ethanol............................. 0 0 0 0
----------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\315\ Dry Mill corn ethanol plant using natural gas with 2022
energy use and dry DDGS.
\316\ Payback periods were not calculated for ethanol made from
corn starch for the advanced biofuel reduction goals of 50% and 60%
since this corn ethanol does not qualify under EISA as a potential
advanced biofuel.
\317\ Dry Mill corn ethanol plant using natural gas with 2022
energy use and w/CHP, Fractionation, Membrane Separation, and Raw
Starch Hydrolysis (wet DGS).
\318\ Dry Mill corn ethanol plant using coal with 2022 energy
use and dry DDGS.
\319\ Dry Mill corn ethanol plant using biomass with 2022 energy
use and dry DDGS.
---------------------------------------------------------------------------
As described in Section VI.B.5, we have focused our lifecycle GHG
analysis on two ways of accounting for GHG emissions over time. In one
set of results we consider lifecycle GHG emissions over 100 years and
discount future emissions with a 2% discount rate. In the other set of
results we consider 30 years of GHG emissions with no discounting of
future emissions (i.e., 0% discount rate). Whereas the discussion
immediately above focused on lifecycle GHG impacts assuming 100 years
with a 2% discount rate and 30 years with no discount rate, Table
VI.C.2-2 shows the lifecycle GHG emissions reductions estimates with a
variety of time periods and discount rates.
Table VI.C.2-2--Lifecycle GHG Emissions Changes of Select Biofuels Relative to the 2005 Petroleum Baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lifecycle GHG emissions changes of select biofuels relative to the 2005 petroleum baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
Time horizon 30 Years 50 Years 100 Years
--------------------------------------------------------------------------------------------------------------------------------------------------------
Discount rate 0% 2% 3% 7% 0% 2% 3% 7% 0% 2% 3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Corn Ethanol 5% 18% 25% 54% -17% -2% 7% 44% -36% -16% -4% 41%
Dry Mill NG
Corn Ethanol -14% -1% 6% 35% -36% -21% -12% 25% -55% -35% -23% 22%
Best Case Dry Mill NG
Corn Ethanol 34% 46% 53% 83% 11% 27% 35% 72% -8% 13% 24% 69%
Dry Mill Coal
Corn Ethanol -18% -6% 1% 31% -41% -25% -17% 20% -60% -39% -28% 16%
Dry Mill Biomass
Soybean Biodiesel............... 4% 20% 29% 68% -24% -4% 7% 55% -48% -22% -7% 51%
Waste Grease Biodiesel.......... -80% -80% -80% -80% -80% -80% -80% -80% -80% -80% -80% -80%
Sugarcane Ethanol............... -27% -17% -11% 12% -45% -32% -26% 3% -61% -44% -35% 1%
Switchgrass Ethanol............. -124% -122% -121% -115% -128% -125% -124% -117% -131% -128% -126% -117%
Corn Stover Ethanol............. -116% -117% -117% -118% -115% -116% -116% -117% -114% -115% -115% -117%
--------------------------------------------------------------------------------------------------------------------------------------------------------
D. Thresholds
EISA established GHG thresholds for each category of renewable fuel
that it mandates. EISA also provided EPA with the authority to adjust
the threshold levels for each category of renewable fuels if certain
requirements are met. Renewable fuels must achieve a 20% reduction in
lifecycle greenhouse gas emissions compared to the average lifecycle
greenhouse gas emissions for gasoline or diesel sold or distributed as
transportation fuel in 2005. Due to the grandfathering provisions of
EISA as adopted in this rule, this threshold only pertains to renewable
fuel produced at plants to be constructed in the future. EPA is
permitted to adjust this threshold to as low as 10%, based on the
``maximum achievable level, taking cost into consideration, for natural
gas fired corn-based ethanol plants allowing for the use of a variety
of technologies.'' Based on our analysis, there are a number of corn
ethanol natural gas plant configurations that could meet the 20%
reduction in GHG emissions thresholds in 2022 if modeling emission over
a 100 year time frame and then discounting these emissions 2%.
Therefore, based on this assessment, we believe that an adjustment to
the 20% threshold would be unnecessary and we are proposing to maintain
it at the 20% level if we adopt the 100 year, 2% discounting
methodology.
On the other hand, based on our current analyses, if we adopt an
assessment methodology which assesses emissions over just 30 years,
then no currently analyzed natural gas-fired corn ethanol pathway will
meet the 20% threshold. However, some of the natural gas corn ethanol
pathways do
[[Page 25049]]
have lifecycle GHG emission benefits in the 10% to 20% range. Corn
ethanol is expected to be the major biofuel contributing to meeting the
renewable fuel standards through at least the middle of the next
decade. Therefore, if we adopt a 30 year timeframe for emissions
assessment and do not discount the results, we may adjust the renewable
fuel thresholds to the minimum level as necessary to incorporate at
least a few of the best GHG pathways for corn ethanol. While this
adjusted threshold level could be revised based on pathway analyses
done for the final rule, at this time we would intend to allow a full
10% adjustment of the renewable fuel threshold, down to a threshold
value of 10% reduction compared to the 2005 gasoline baseline.
Cellulosic biofuels must meet a 60% reduction in GHG emissions
relative to the petroleum baseline. EPA is permitted to adjust this
threshold to as low as 50% if it is ``not commercially feasible for
fuels made using a variety of feedstocks, technologies, and processes''
to achieve the 60% threshold. Our initial analysis indicates that
cellulosic biofuels from corn stover, switchgrass, and bagasse will all
meet the 60% threshold regardless of whether we use to 100 year, 2%
discount methodology or the 30 year analysis time frame without
discounting. Furthermore, we believe most fuels made from other
cellulosic feedstocks would as well. Therefore we do not believe it is
necessary to adjust the threshold for cellulosic biofuel at this time.
Biomass-based diesel must achieve a 50% reduction in GHG emissions
relative to petroleum-based diesel. EPA is permitted to adjust this
threshold to as low as 40% if it is ``not commercially feasible for
fuels made using a variety of feedstocks, technologies, and processes''
to meet the 50% level. For biomass-based diesel, our analysis indicates
that biodiesel from waste oils such as yellow grease and tallow would
meet the 50% threshold, and we anticipate that biodiesel from chicken
waste and non-food grade corn oil fractionation would as well
regardless of whether we use a 100 year, 2% discount methodology or the
30 year analysis time frame without discounting. However, our current
analysis indicates that there is insufficient feedstock from waste
grease and fats to meet the one billion gallon volumetric requirement
under EISA. Biodiesel from soy oil (and we believe biodiesel from other
food grade vegetable oils) would reduce GHG emissions by no more than
22% using a 100 year, 2% discount methodology and would be estimated to
increase GHG emissions if we analyze emission impacts over 30 years
whether the emissions are discounted or not. Even if EPA adjusted the
biomass-based diesel standard to the minimum allowable level of 40%,
soybean-based biodiesel would still not meet the GHG emissions
reductions threshold for biomass based diesel fuel. One option for
meeting the volumetric requirement and the emissions reduction
threshold, assuming a 100 year timeframe and a 2% discount rate for GHG
emission impacts would be to allow biodiesel producers to average the
emissions reductions from a blend of soy oil or food grade vegetable
oil-based biodiesel with waste oil based biodiesel, as discussed in
more detail in Section VI.E. However, this approach may still be
insufficient to ensure that the required volumes of biomass-based
diesel can be produced unless other sources of biomass-based diesel
become available. Therefore, we invite comments on whether it be
appropriate to both reduce the threshold to 40% and allow biodiesel
producers to average their emissions to meet the one billion gallon
volumetric requirement as discussed below in Section VI.E.3.c.
Advanced biofuels must achieve a 50% reduction in GHG emissions.
EPA is permitted to adjust this threshold to as low as 40% if it is
``not commercially feasible for fuels made using a variety of
feedstocks, technologies, and processes'' to achieve the 50% threshold.
Our current lifecycle analysis suggests that sugarcane based ethanol
only offers an estimated 44% reduction in GHG emissions relative to the
gasoline it replaces when assessing 100 years of emission impacts and
discounting these emissions 2%, and an estimated 27% reduction when
assessing 30 years of emission impacts with no discounting. Therefore,
it would not qualify as an advanced biofuel if we did not adjust the
50% GHG threshold. We are also unaware of other renewable fuels that
may be available in sufficient volumes over the next several years to
allow the statutory volume requirements for advanced biofuel to be met.
As a result, we are proposing that the GHG threshold for advanced
biofuels be adjusted to 44% or potentially as low as 40% depending on
the results from the analyses that will be conducted for the final
rule. Based on our current analysis of the lifecycle GHG impacts of
sugarcane ethanol, such an adjustment would help ensure that the volume
mandates for advanced biofuel can be met.
We invite comments on these proposed thresholds and our basis for
them.
E. Assignment of Pathways to Renewable Fuel Categories
The lifecycle analyses that we conducted for a variety of fuel
pathways formed the basis for our determination of which pathways would
be permitted to generate RINs, and to which of the four renewable fuel
categories (cellulosic biofuel, biomass-based diesel, advanced biofuel,
and renewable fuel) those RINs should be assigned. This determination
involved comparing the lifecycle GHG performance estimates to the GHG
thresholds associated with each renewable fuel category, discussed in
Section VI.D above. In addition, each of the four renewable fuel
categories is defined in EISA to include or exclude certain types of
feedstocks and production processes, and these definitions also played
a role in determining the appropriate category for each pathway. This
section describes our proposed assignments of pathways to one of the
four renewable fuel categories. The GHG lifecycle values used in this
assignment of fuel pathways to the four renewable fuel categories were
based on the lifecycle analysis results over a 100-year timeframe and
using a 2% discount rate, as described in Section VI.C. Different
assignments of pathways to the four renewable fuel categories would
occur with different lifecycle results, but we propose that the same
assignment methodology would be followed regardless.
1. Statutory Requirements
EISA establishes requirements that are common to all four
categories of renewable fuel in addition to requirements that are
unique to each of the four categories. The common requirements
determine which fuels are valid for generating RINs under the RFS2
program. For instance, all renewable fuel must be made from renewable
biomass, which defines the types of feedstocks that can be used to
produce renewable fuel that is valid under the RFS2 program, and also
defines the types of land on which crops can be grown if those crops
are used to produce valid renewable fuel under the RFS2 program. See
Section III.B.4 for a more detailed discussion of renewable biomass.
Moreover, all renewable fuel must displace fossil fuel present in
transportation fuel, or be used as home heating oil or jet fuel.
The requirements that are unique to each of the four categories
provide a basis for assigning each pathway to a category. For each of
the four categories of renewable fuel, EISA provides a definition,
specifies the associated GHG
[[Page 25050]]
thresholds, lists the allowable feedstocks and/or fuel types, and in
some cases provides exclusions. Table VI.E.1-1 summarizes these
requirements as we are applying them under the proposed RFS2 program.
Table VI.E.1-1--Requirements for Renewable Fuel Categories
----------------------------------------------------------------------------------------------------------------
Biomass-based
Cellulosic biofuel diesel Advanced biofuel Renewable fuel
----------------------------------------------------------------------------------------------------------------
GHG threshold................... 60%............... 50% \a\........... 40-44% \a\........ 20% a, b.
Eligible Inclusions............. Renewable fuel Any renewable fuel All cellulosic All advanced
made from that is a diesel biofuel and biofuel, and any
cellulose, fuel substitute. biomass-based other fuel made
hemicellulose, or diesel, as well from renewable
lignin. as other biomass that is
renewable fuels used to replace
including ethanol or reduce the
from sugar, quantity of
starch, or waste fossil fuel
materials, present in a
biogas, and transportation
butanol and other fuel.
alcohols.
Exclusions...................... .................. Any renewable fuel Ethanol derived
made from from corn starch.
coprocessing with
petroleum.
----------------------------------------------------------------------------------------------------------------
\a\ As discussed in Section VI.D, we are seeking comment on the need to adjust the thresholds, and are proposing
that the GHG threshold for advanced biofuels be adjusted to as low as 40%.
\b\ 20% threshold does not apply to grandfathered volumes. See discussion in Section III.B.3.
2. Assignments for Pathways Subjected to Lifecycle Analyses
There are a wide variety of pathways (unique combinations of
feedstock, fuel type, and fuel production process) that could result in
renewable fuel that would be valid under the RFS2 program. As described
earlier in this section, we conducted lifecycle analyses for some of
these pathways, and these analyses allowed us to determine if the GHG
thresholds shown in Table VI.E.1-1 would be met under the assumption of
a 100-year timeframe and discount rate of 2%. For other pathways that
we have not yet subjected to lifecycle analyses, there were some cases
in which we could nevertheless still make moderately confident
determinations as to the likely GHG impacts by making comparisons to
the pathways that we did analyze. A discussion of these other
determinations is provided in Section VI.E.3 below.
For pathways that we subjected to lifecycle analysis, we were able
to assign each pathway to one of the four renewable fuel categories
defined in EISA by comparing the descriptions of each pathway and its
associated GHG performance to the requirements shown in Table VI.E.1-1.
The results are shown in Table VI.E.2-1.
Table VI.E.2-1--Proposed Assignment of Pathways to One of the Four
Renewable Fuel Categories for Pathways Subjected to Lifecycle Analyses
------------------------------------------------------------------------
------------------------------------------------------------------------
Cellulosic biofuel pathways....... Ethanol produced from corn stover or
switchgrass in a process that uses
enzymes to hydrolyze the cellulose
and hemicellulose.
Biomass-based diesel pathways..... Biodiesel (mono alkyl esters)
produced from waste grease and
waste oils.
Advanced biofuel pathways......... Ethanol produced from sugarcane
sugar in a process that uses
sugarcane bagasse for process heat.
\a\
Renewable fuel pathways........... Ethanol produced from corn starch in
a process that uses biomass for
process heat.
Ethanol produced from corn starch in
a process that includes:
--Dry mill plant.
--Process heat derived from
natural gas.
--Combined heat and power (CHP).
--Fractionation of feedstocks.
--All distillers grains are
dried.
Ethanol produced from corn starch in
a process that includes:
--Dry mill plant.
--Process heat derived from
natural gas.
--All distillers grains are wet.
Ethanol produced from corn starch in
a process that includes:
--Dry mill plant.
--Process heat derived from coal.
--Combined heat and power (CHP).
--Fractionation of feedstocks.
--Membrane separation of ethanol.
--Raw starch hydrolysis.
--All distillers grains are
dried.
Ethanol produced from corn starch in
a process that includes:
--Dry mill plant.
--Process heat derived from coal.
--Combined heat and power (CHP).
--Fractionation of feedstocks.
--Membrane separation of ethanol.
--All distillers grains are wet.
[[Page 25051]]
Biodiesel (mono alkyl esters)
produced from soybean oil.
------------------------------------------------------------------------
\a\ Our current analysis concludes that ethanol from sugarcane sugar
would have a GHG performance of 44% in comparison to gasoline under
our assumed 100-year timeframe and 2% discount rate. Since this falls
short of the 50% GHG threshold for advanced biofuel, we have
categorized it as general renewable fuel. However, we request comment
on lowering the applicable GHG threshold for advanced biofuel so that
ethanol from sugarcane sugar could be categorized as advanced biofuel.
See further discussion in Section VI.D.
In addition, our lifecycle analyses also identified pathways that
did not meet the minimum 20% GHG threshold under an assumed 100-year
timeframe and 2% discount rate, and thus would be prohibited from
generating RINs unless a facility met the prerequisites for
grandfathering as described in Section III.B.3. These prohibited
pathways all involved the production of ethanol from corn starch in a
process that uses natural gas or coal for process heat, but which does
not meet any of the process technology requirements listed in Table
VI.E.2-1. Our proposal for temporary D codes in Sec. 80.1416 would
explicitly prohibit the generation of RINs for these pathways.
The proposed assignments of individual pathways to one of the four
renewable fuel categories shown in the table above assumed a 100-year
timeframe and discount rate of 2% for lifecycle GHG emission impacts.
The assignments would be different if we had assumed a different
timeframe and discount rate. By comparing the relative GHG emission
reductions shown in Table VI.C.1-2 to the thresholds in Table VI.E.1-1,
a variety of different assignments is possible covering timeframes of
30, 50, and 100 years, and discount rates of 0%, 2%, 3%, and 7%. For
instance, under the assumption of 30 years and no discounting,
switchgrass ethanol and corn stover ethanol would continue to be
categorized as cellulosic biofuel and biodiesel made from waste grease
would continue to be categorized as biomass-based diesel. However,
sugarcane ethanol could no longer be potentially categorized as
advanced biofuel but instead would be categorized as renewable fuel.
Moreover, some pathways would not meet the minimum threshold of 20% for
renewable fuel, and so could not generate RINs if the volume was not
grandfathered. This would include soybean biodiesel and all of the corn
starch ethanol pathways shown in Table VI.E.2-1 produced from newly
constructed plants not meeting the grandfathering criteria discussed in
Section III.B.3.
3. Assignments for Additional Pathways
We were not able to conduct lifecycle modeling for all potential
pathways in time for this proposed rulemaking. Instead, we focused the
lifecycle GHG emissions analysis on the feedstocks that, based on FASOM
predictions and other information, we anticipate could contribute the
largest volumes to the renewable fuel pool and the production processes
representing the largest shares of the market. As more information
becomes available, we anticipate that we will be updating the lifecycle
methodology and expanding the list of emission factors.
Beyond the pathways that we explicitly subjected to lifecycle
analysis, there are additional pathways that may not currently be
significant contributors to the volume of renewable fuel produced, but
their volumes could increase in the future. Moreover, we believe it is
important that as many pathways as possible be included in the lookup
table in the regulations to help ensure that the volume requirements in
EISA can be met and to encourage the development of new fuels. To this
end, we evaluated these additional pathways to determine if they could
be deemed valid for generation of RINs, and if so which of the four
renewable fuel categories they would fall into. This section describes
our evaluation of these additional pathways and the resulting proposed
assignment to one or more of the four renewable fuel categories.
a. Ethanol From Starch
Our lifecycle analysis focused on ethanol from corn starch.
However, there are a variety of other sources of starch that use or
could use a very similar process for conversion to ethanol. These
include wheat, barley, oats, rice, and sorghum. Some existing corn-
ethanol facilities already use small amounts of starch from these other
plants along with corn in their production of ethanol.
Although we have not explicitly analyzed the land use or processing
impacts of these other starch plants on their lifecycle GHG
performance, we believe it would be reasonable to assume similar
impacts to corn in terms of the types of land that would be displaced
and other aspects of producing and transporting the feedstock.
Therefore, we propose that the pathways shown in Table VI.E.2-1 for
ethanol produced from corn starch also be applied to ethanol produced
from other sources of starch.
The lifecycle analyses conducted for this proposal only examined
cases in which a corn-ethanol facility dried 100% of its distiller's
grains or left 100% of its distiller's grains wet. The treatment of the
distiller's grains for corn-ethanol facilities impacts the
determination of whether the 20% GHG threshold for renewable fuel has
been met. However, in practice some facilities may dry only a portion
of their distiller's grains and leave the remainder wet. As described
in Section III.D.3, we are proposing that a facility that dried only a
portion of its distiller's grain would be treated as if it dried 100%
of its grains, and would thus need to implement additional GHG-reducing
technologies as described in the lookup table in order to qualify to
generate RINs. However, we are also taking comment on whether a
selection of pathways should be included in the lookup table that
represent corn-ethanol facilities that dry only a portion of their
distiller's grains. We also request comment on whether RINs could be
assigned to only a portion of the facility's ethanol in cases wherein
only a portion of the distiller's grains are dried.
b. Renewable Fuels from Cellulosic Biomass
In analyzing the lifecycle GHG impacts of cellulosic ethanol, we
determined that ethanol produced from corn stover or switchgrass
through a process using enzymatic hydrolysis followed by fermentation
of the resulting sugars met the GHG threshold of 60% for cellulosic
biofuel by a wide margin (regardless of the discount rate and the time
period over which the lifecycle GHG emissions are discounted). However,
there are many other potential sources of cellulosic biomass, and other
processing mechanisms to convert cellulosic biomass into fuel. For some
of these cases, we believe that we can make determinations regarding
whether the GHG thresholds shown in Table VI.E.1-1 are likely to be
met. In addition, as the forestry component of the FASOM model is
incorporated into the analysis,
[[Page 25052]]
we will analyze pathways using planted trees, tree residue, and slash
and pre-commercial thinnings from forestland, as qualify under the
renewable biomass definition, for feedstock.
Cellulosic biomass sources include waste biomass such as corn
stover, and crops grown specifically for fuel production such as
switchgrass. While cellulosic crops grown for the purpose of fuel
production could have land use implications in a lifecycle GHG
analysis, waste materials produced during the harvesting of some other
type of crop would not. Given that the GHG impacts of a fermentation-
based fuel production process are likely to be very similar for
cellulose from a variety of feedstocks, we believe it would be
reasonable to conclude that any cellulosic feedstock from a waste
source that is subjected to enzymatic hydrolysis followed by
fermentation of the resulting sugars would be very likely to meet the
60% GHG threshold for cellulosic biofuel. Therefore, we propose that
cellulosic ethanol produced through an enzymatic hydrolysis process
followed by fermentation using any eligible waste cellulosic feedstock
would be determined to meet the 60% GHG threshold for cellulosic
biofuel. This would include such wastes as wheat straw, rice straw,
sugarcane bagasse, forest slash and thinnings, and yard waste.
As stated earlier, cellulosic crops grown for the purpose of fuel
production could have land use implications in a lifecycle GHG
analysis. However, the only cellulosic crop that we subjected to
lifecycle analysis was switchgrass which had a relatively small impact
of land-use. Other cellulosic crops that have been considered for fuel
production include miscanthus and trees such as poplar and willow. It
is possible that the land use impacts of miscanthus and planted trees
could be different from that for switchgrass. For instance, while
switchgrass can be grown on marginal lands, planted trees may require
more arable land to thrive. However, according to our lifecycle
analysis for switchgrass, the land use impacts could significantly
increase and the 60% threshold for cellulosic biofuel would still be
met. Therefore, we propose that the pathways shown in Table VI.E.2-1
for ethanol produced from switchgrass through an enzymatic hydrolysis
process followed by fermentation also be applied to ethanol produced
from miscanthus and planted trees. We intend to examine this pathway
more closely for the final rule to determine if this categorization is
appropriate, and request comment on the land use impacts of miscanthus
and planted trees.
Renewable fuels can also be produced from cellulosic biomass
through various thermochemical processes rather than enzymatic
hydrolysis followed by fermentation. One example of such thermochemical
processes would be biomass gasification to produce ``syngas'' (a
mixture of hydrogen and carbon monoxide) which is then catalytically
synthesized through a Fischer-Tropsch process to produce ethanol,
diesel, gasoline, or other transportation fuels. Another example would
be a catalytic depolymerization process in which the biomass is first
catalytically cracked to smaller molecules and then polymerized under
specific combinations of temperature, pressure, and residence time to
produce a transportation fuel. We have not conducted a lifecycle
analysis of these pathways, but we believe that we can nonetheless make
a reasonable determination regarding the appropriate renewable fuel
category. For instance, we would expect that the GHG emissions produced
during fuel production would be higher for a thermochemical process
than for enzymatic hydrolysis due to the need for greater process heat
produced through the combustion of fossil fuels. However, the yield of
fuel produced per ton of biomass is likely to be greater for
thermochemical processing due to the conversion of the lignin to fuel
in addition to the cellulose and hemicellulose. Thus, while the
lifecycle GHG analyses we conducted for corn stover and switchgrass
demonstrated that the 60% GHG threshold for cellulosic biofuel would be
met by a wide margin, this margin may be smaller if a thermochemical
process was used. While we intend to conduct further analyses of this
family of pathways for the final rule, we believe that a change from
enzymatic hydrolysis to a thermochemical process would be expected to
meet the 60% GHG threshold associated with cellulosic biofuel.
Therefore, we propose that the use of corn stover or other waste
cellulosic biomass, switchgrass, or planted trees in a thermochemical
process would qualify as cellulosic biofuel under the RFS2 program.
This would include pathways that produce ethanol, cellulosic diesel, or
cellulosic gasoline. Since cellulosic diesel fuel produced in this way
would also meet the requirements for biomass-based diesel, we propose
to allow it to be categorized as either cellulosic biofuel or biomass-
based diesel at the producer's discretion. See further discussion of
this issue in Section III.D.2.a. We request comment on our proposed
assignment of categories for renewable fuels produced through a
thermochemical process, as well as data and other information relating
to the various types of thermochemical fuel production processes.
c. Biodiesel
Our lifecycle analysis of biodiesel (mono alkyl esters) produced
from waste greases/oils demonstrated that the 50% GHG threshold for
biomass-based diesel would be met. Much of the GHG benefit of these
waste greases/oils derives from the fact that they have no land use
impacts. While we did not subject corn oil that is non-food grade to
lifecycle analysis, it is likely that it would also have no land use
impacts. Moreover, such non-food grade corn oil would require nearly
the same process energy to convert it into biodiesel. Therefore, we
propose that the pathway shown in Table VI.E.2-1 for biodiesel produced
from waste greases/oils also be applied to biodiesel produced from non-
food grade corn oil. We intend to analyze this pathway in more depth
for the final rule.
Our lifecycle analysis of biodiesel produced from soybean oil may
also be applicable to biodiesel produced from other types of virgin
(not waste) oils. This would include canola oil, rapeseed oil,
sunflower oil, and peanut oil. While we have not conducted a detailed
assessment of the land use impacts of these other virgin oils, it is
possible that they would meet the 20% threshold for generic renewable
fuel. Therefore, we propose that the pathway shown in Table VI.E.2-1
for biodiesel produced from soybean oil also be applied to biodiesel
produced from other these virgin oils. We request comment on whether
this is appropriate.
Although our proposed list of RIN-generating pathways would allow
biodiesel made from waste greases/oils to qualify as biomass-based
diesel, it is likely that there would be insufficient quantities of
these feedstocks to reach the 1.0 billion gallon requirement by 2012.
Biodiesel produced from soybean oil would not qualify as biomass-based
diesel, but instead would be categorized as generic renewable fuel
based on our current analysis of its lifecycle GHG performance.
However, biodiesel production facilities can process either soybean oil
or waste grease with relatively minor changes in operations, and many
facilities that formerly used soybean oil have recently switched to
waste grease due to its more favorable economics. Since the GHG
performance
[[Page 25053]]
of biodiesel made from waste greases/oils met the 50% GHG threshold by
a wide margin, and since it is common industry practice for biodiesel
facilities to use these two feedstock sources, we believe it may be
appropriate to allow a biodiesel production facility to average the GHG
benefit generated through the use of waste grease with the lower GHG
performance of biodiesel produced from soybean oil at the same
facility.
We recognize that an approach in which we allow a biodiesel
production facility to average the GHG benefit of waste grease with
that from soybean oil raises questions about whether similar averaging
could be allowed for other combinations of feedstocks, other types of
fuel, or across multiple facilities within the same company. While we
believe that the circumstances surrounding biodiesel production are
somewhat unique--two different feedstocks subjected to essentially the
same production process in a single facility--we nevertheless request
comment on the appropriateness of such an averaging approach for
biodiesel.
Based on our lifecycle analyses, biodiesel produced from waste
grease has a GHG performance of 80% reduction from the conventional
diesel baseline, while biodiesel produced from soybean oil has a GHG
performance of 22% reduction. In order to meet the GHG threshold of 50%
for biomass-based diesel, a biodiesel production facility would need to
use a minimum of 48% waste grease and a maximum of 52% soybean oil.
Thus, a pathway that would allow a biodiesel production facility to
designate all of its biodiesel as biomass-based diesel would include a
requirement that the producer demonstrate that every batch has been
produced from no less than 48% waste grease and no more than 52%
soybean oil.
Although this approach would allow the total volume of biomass-
based diesel to be larger than if waste greases/oils alone qualified,
it is still possible than the 1.0 billion gallon requirement would not
be met due to limits on the availability of waste greases and oils. For
instance, we estimate that the total volume of waste greases and oils
may be no larger than 0.3-0.4 billion gallons. As a result, we request
comment on whether it would also be appropriate to lower the GHG
threshold for biomass-based diesel. If this GHG threshold were lowered
to 40%, a biodiesel production facility would only need to use a
minimum of 31% waste greases/oils instead of 48%.
We recognize that it may be difficult for a biodiesel production
facility to process a consistent mixture of waste grease and soybean
oil every day. Therefore, we request comment on alternative approaches.
For instance, if a biodiesel production facility processed only waste
grease for the first 175 days (48% x 365 days) of a calendar year, we
could allow it to designate any biodiesel produced from soybean oil for
the remainder of the year as biomass-based diesel. However, this may be
difficult for some producers who must contend with cold temperature
storage and blending issues in the early part of a calendar year by
processing only soybean oil. Alternatively, we could allow a company to
average the production at all of its facilities, where one facility
processed only waste grease and another processed only soybean oil.
Finally, we request comment on an alternative approach in which an
obligated party, rather than the biodiesel production facility, would
demonstrate that a minimum number of waste grease-based biodiesel RINs
is used to meet the biomass-based diesel standard in comparison to the
number of soybean oil-based biodiesel RINs. In essence, the averaging
would be carried out by the obligated party instead of the biodiesel
producer. In this approach, biodiesel RINs would not be placed into
biomass-based diesel category shown in Table VI.E.1-1, but instead
would be placed into two separate categories as waste grease RINs or
soybean oil RINs. This designation would require that the list of
applicable D codes for use in the RIN be expanded from four to six as
shown in Table VI.E.3.c-1.
Table VI.E.3.c-1--Alternative Approach to D Codes for Averaging Waste
Grease and Soybean Oil Biodiesel RINs in Compliance
------------------------------------------------------------------------
Alternative approach
D value Proposal meaning meaning
------------------------------------------------------------------------
1................ Cellulosic biofuel........ Cellulosic biofuel
2................ Biomass-based diesel...... Biomass-based diesel
3................ Advanced biofuel.......... Biodiesel made from
soybean oil
4................ Renewable fuel............ Biodiesel made from waste
grease
5................ (Not applicable).......... Advanced biofuel
6................ (Not applicable).......... Renewable fuel
------------------------------------------------------------------------
Since other types of renewable fuel may still qualify as biomass-
based diesel, we would retain a separate D code for this category under
this approach. This could allow biodiesel producers who choose the
process a minimum of 48% waste greases/oils each day to continue to
assign a D code of 2 to their biodiesel.
An obligated party could use any combination of RINs with a D code
of 2, 3, or 4 in order to comply with the biomass-based diesel
standard. However, he would also be subject to an additional
requirement that the ratio of D=3 RINs to D=4 RINs must be less than
1.08. This criterion would ensure that a minimum of 47 RINs
representing biodiesel from waste grease would be used for compliance
purposes for every 53 RINs representing biodiesel from soybean oil that
are also used for compliance.
We request comment on these alternative approaches to the treatment
of biodiesel.
d. Renewable Diesel Through Hydrotreating
We did not conduct a lifecycle analysis for the production of non-
ester renewable diesel through a hydrotreating process. However, we
believe that our analysis of biodiesel provides sufficient information
to allow us to designate the renewable fuel category for various
pathways leading to the production of renewable diesel.
Renewable diesel is generally made from the same feedstocks as
biodiesel, namely soybean oil, waste greases/oils, tallow, and chicken
fat. Therefore, the GHG impacts associated with producing/collecting
the feedstock and transporting it to the production facility would be
the same regardless of whether the final product is biodiesel or
renewable diesel.
The fossil energy requirements of the production process contribute
a relatively small amount to the overall GHG performance for biodiesel.
For example, the 50% GHG threshold would still be met for biodiesel
produced from waste grease even if the fossil energy requirements
doubled. As a result, compared to the transesterification process used
to produce biodiesel, any small variations in fossil energy
requirements for renewable diesel production in a hydrotreater would be
unlikely to change compliance with the broad categories created by the
GHG thresholds for biomass-based diesel and generic renewable fuel.
Therefore, we believe that it would be appropriate to assign applicable
renewable fuel categories to renewable diesel pathways in parallel with
the assignments we are proposing for biodiesel, including the potential
for averaging of soyoil and waste grease derived volumes. Renewable
diesel produced from waste grease, tallow, or chicken fat in a
hydrotreater that does not coprocess petroleum feedstocks would be
[[Page 25054]]
categorized as biomass-based diesel. Renewable diesel produced from
waste grease, tallow, or chicken fat in a hydrotreater that does
coprocess petroleum feedstocks would be categorized as advanced
biofuel. Finally, renewable diesel produced from soybean oil in a
hydrotreater would be categorized as generic renewable fuel.
4. Summary
Based on the discussion above, we have identified 15 pathways that
we propose could be used to produce fuel that would meet the volume
requirements in EISA assuming a 100 year analysis time frame and
discounting GHG emissions over time by 2%. As noted above, these
pathways would be adjusted should we adopt other time frames or
discount rates (including a zero discount rate) for the final rule.
Each pathway would be assigned a D code for use in generating RINs that
corresponds to one of the four renewable fuel categories. Our proposed
list of allowable pathways is shown in Table VI.E.4-1.
Table VI.E.4-1--Applicable Categories for Each Fuel Pathway \a\
----------------------------------------------------------------------------------------------------------------
Production process
Fuel type Feedstock requirements Category
----------------------------------------------------------------------------------------------------------------
Ethanol.............................. Starch from corn, --Process heat derived Renewable fuel.
wheat, barley, oats, from biomass.
rice, or sorghum.
Ethanol.............................. Starch from corn, --Dry mill plant....... Renewable fuel.
wheat, barley, oats,
rice, or sorghum.
--Process heat derived
from natural gas.
--Combined heat and
power (CHP).
--Fractionation of
feedstocks.
--Some or all
distillers grains are
dried.
Ethanol.............................. Starch from corn, --Dry mill plant....... Renewable fuel.
wheat, barley, oats,
rice, or sorghum.
--Process heat derived
from natural gas.
--All distillers grains
are wet.
Ethanol.............................. Starch from corn, --Dry mill plant....... Renewable fuel.
wheat, barley, oats,
rice, or sorghum.
--Process heat derived
from coal.
--Combined heat and
power (CHP).
--Fractionation of
feedstocks.
--Membrane separation
of ethanol.
--Raw starch hydrolysis
--Some or all
distillers grains are
dried.
Ethanol.............................. Starch from corn, --Dry mill plant....... Renewable fuel.
wheat, barley, oats,
rice, or sorghum.
--Process heat derived
from coal.
--Combined heat and
power (CHP).
--Fractionation of
feedstocks.
--Membrane separation
of ethanol.
--All distillers grains
are wet.
Ethanol.............................. Cellulose and --Enzymatic hydrolysis Cellulosic biofuel.
hemicellulose from of cellulose.
corn stover,
switchgrass,
miscanthus, wheat
straw, rice straw,
sugarcane bagasse,
forest waste, yard
waste, or planted
trees.
--Fermentation of
sugars.
--Process heat derived
from lignin.
Ethanol.............................. Cellulose and --Thermochemical Cellulosic biofuel.
hemicellulose from gasification of
corn stover, biomass.
switchgrass,
miscanthus, wheat
straw, rice straw,
sugarcane bagasse,
forest waste, yard
waste, or planted
trees.
--Fischer-Tropsch
process.
Ethanol.............................. Sugarcane sugar........ --Process heat derived Advanced biofuel.
from sugarcane bagasse.
Biodiesel (mono alkyl ester)......... Waste grease, waste --Transesterification.. Biomass-based diesel.
oils, tallow, chicken
fat, or non-food grade
corn oil.
Biodiesel (mono alkyl ester)......... Soybean oil and other --Transesterification.. Renewable fuel.
virgin plant oils.
[[Page 25055]]
Cellulosic diesel.................... Cellulose and --Thermochemical Cellulosic biofuel or
hemicellulose from gasification of biomass-based diesel.
corn stover, biomass.
switchgrass,
miscanthus, wheat
straw, rice straw,
sugarcane bagasse,
forest waste, yard
waste, or planted
trees.
--Fischer-Tropsch
process.
--Catalytic
depolymerization.
Non-ester renewable diesel........... Waste grease, waste --Hydrotreating........
oils, tallow, chicken
fat, or corn oil.
--Dedicated facility Biomass-based diesel.
that processes only
renewable biomass.
Non-ester renewable diesel........... Waste grease, waste --Hydrotreating........ Advanced biofuel.
oils, tallow, chicken
fat, or non-food grade
corn oil.
--Coprocessing facility
that also processes
petroleum feedstocks.
Non-ester renewable diesel........... Soybean oil and other --Hydrotreating........ Renewable fuel.
virgin plant oils.
Cellulosic gasoline.................. Cellulose and --Thermochemical Cellulosic biofuel.
hemicellulose from gasification of
corn stover, biomass.
switchgrass,
miscanthus, wheat
straw, rice straw,
sugarcane bagasse,
forest waste, yard
waste, or planted
trees.
--Fischer-Tropsch
process.
--Catalytic
depolymerization.
----------------------------------------------------------------------------------------------------------------
\a\ Under our assumed 100-year timeframe and 2% discount rate.
As stated earlier, there may be other potential pathways that could
lead to qualifying renewable fuel. While we do not have sufficient
information at this time to evaluate the likely lifecycle GHG impact
and thus assign those pathways to one of the four renewable fuel
categories, we do plan on doing these evaluations for the final rule.
Pathways that we intend to subject to lifecycle analysis include
butanol from starches or oils and renewable diesel from biomass using
pyrolysis or catalytic reforming. We request comment on the inputs
necessary to apply lifecycle analysis to these pathways. We also
request comment on other pathways that should be analyzed and the data
that would be necessary for those analyses.
For pathways that are not included in the lookup table in the final
rule, we are also proposing a regulatory mechanism whereby a producer
could temporarily assign their renewable fuel to one of the four
renewable fuel categories under certain conditions. For further
discussion of this issue, see Section III.D.5.
F. Total GHG Emission Reductions
Our analysis of the overall GHG emission impacts of this proposed
rulemaking was performed in parallel with the lifecycle analysis
performed to develop the individual fuel thresholds described in
previous sections. The same system boundaries apply such that this
analysis includes the effects of three main areas: (a) emissions
related to the production of biofuels, including the growing of
feedstock (corn, soybeans, etc.) with associated domestic and
international land use change impacts, transport of feedstock to fuel
production plants, fuel production, and distribution of finished fuel;
(b) emissions related to the extraction, production and distribution of
petroleum gasoline and diesel fuel that is replaced by use of biofuels;
and (c) difference in tailpipe combustion of the renewable and
petroleum based fuels. As discussed in the previous sections we will be
updating our lifecycle approach for the final rule and there are some
areas that we were not able to quantify at this time, such as secondary
impacts in the energy sector. We are working to include this for our
final rule analysis.
Consistent with the fuel volume feasibility analysis and criteria
pollutant emissions, our analysis of the GHG impacts of increased
renewable fuel use was conducted by comparing the impacts of the 2022
36 Bgal of renewable fuel volumes required by EISA to a projected 2022
reference case of approximately 14 Bgal of renewable fuel volumes.
Similar to what was done to calculate lifecycle thresholds for
individual fuels we considered the change in 2022 of these two volume
scenarios of renewable fuels to determine overall GHG impacts of the
rule. The reference case for the GHG emission comparisons was taken
from the AEO 2007 projected renewable fuel production levels for 2022
prior to enactment of EISA. This scenario provided a point of
comparison for assessing the impacts of the RFS2 standard volumes on
GHG emissions. We ran these multi-fuel scenarios through our FASOM and
FAPRI models and applied the Winrock land use change assumptions to
determine to overall GHG impacts. We were only able to analyze 2022
reference and control cases. However, in reality the impacts of corn
ethanol and soybean biodiesel will be experienced beginning in 2009,
with the impacts of cellulosic ethanol and sugarcane ethanol growing in
later years as their volumes increase.
The main difference between this overall impacts analysis and the
analysis conducted to develop the threshold values for the individual
fuels is that we analyzed the total change in renewable fuels in one
scenario as opposed to looking at individual fuel impacts. When
analyzing the impact of the total 36 billion gallons of renewable fuel,
we also took into account the agricultural sector interactions
necessary to produce the full complement of feedstock. We also
[[Page 25056]]
considered a mix of plant types and configurations for the 2022
renewable fuel production representing the mix of plants we project to
be in operation in 2022. This is based on the same analysis used in the
plant location and fuel feasibility analysis described in Section V.B.
For this overall impacts analysis we used a different petroleum
baseline fuel that is offset from renewable fuel use. The lifecycle
threshold values are required by EISA to be based on a 2005 petroleum
fuel baseline. For this inventory analysis of the overall impacts of
the rule we considered the crude oil and finished product that would be
replaced in 2022. Displaced petroleum product analysis was consistent
with work performed for the energy security analysis described in
Section IX.B. For this analysis we consider that 25% of displaced
gasoline will be imported gasoline. For the domestic production we
assumed replacement of the 2022 crude mix which is projected to include
7.6% tar sands and 3.8% Venezuelan heavy crude which is higher then the
projected mix in 2005 which includes 5% tar sands and 1% Venezuelan
heavy crude.
Given these many differences, simply adding up the individual
lifecycle results determined in Section VI.C. multiplied by their
respective volumes would yield a different assessment of the overall
rule impacts. The two analyses are separate in that the overall rule
impacts capture interactions between the different fuels that can not
be broken out into per fuels impacts, while the threshold values
represent impacts of specific fuels but do not account for all the
interactions.
For example, when we consider the combined impact of the different
fuel volumes when analyzed separately, the overall land use change is
9.0 million acres. However, when we analyze the volume changes all
together, the overall land use change is approximately 10% higher.
The primary reason for the difference in acre change between the
sum of the individual fuel scenarios and the combined fuel scenarios is
that when looking at individual fuels there is some interaction between
different crops (e.g., corn replacing soybeans), but with combined
volume scenario when all mandates need to be met there is less
opportunity for crop replacement (e.g., both corn and soybean acres
needed) and therefore more land is required.
Important findings of our analysis include:
As with the threshold lifecycle calculations, assumptions
about timing to consider impacts over and discount rates will have a
significant impact on results.
We estimate the largest overall agricultural sector impact
is an increase in land use change impacts, reflecting the shift of crop
production internationally to meet the biofuel demand in the U.S.
Increased crop production internationally resulted in land use change
emissions associated with converting land into crop production.
Our analysis indicates that overall domestic agriculture
emissions would increase. There is a relatively small increase in total
domestic crop acres however, there are additional inputs required due
to the removal of crop residues. The assumption is that removal will
require more inputs to make up for lost residue nutrients. These
additional inputs result in GHG emissions from production and from
N2O releases from application. This effect is somewhat
offset by reductions due to lower livestock production. These results
are dependent on our agricultural sector input and emission assumptions
that are being updated for the final rule (e.g., N2O
emission factor work).
In particular due to this international impact, the
potential overall GHG emission reductions of biofuels produced from
food crops such as corn ethanol and soy biodiesel are significantly
impacted. Large near term emission increases due to land use change
require a number of years before the emission reductions due to corn
ethanol and soy biodiesel use will offset the near term emission
increase as discussed in the threshold calculation section.
Cellulosic biofuels contribute by far the most to the
total emission reductions due to both their superior per gallon
emission reductions and the large volume of these fuels anticipated to
be used by 2022.
The timing of the impact of land use change and ongoing renewable
fuels benefits were discussed in the previous lifecycle fuel threshold
section. The issue is slightly different for this analysis since we are
considering absolute tons of emissions and not determining a threshold
comparison to petroleum fuels. However the results can be presented in
a similar manner to our individual fuels analysis in that we can
determine net benefits over time with different discount rates and over
a different time frame for consideration.
As discussed in previous sections on lifecycle GHG thresholds there
is an initial one time release from land conversion and smaller ongoing
releases but there are also ongoing benefits of using renewable fuels
over time replacing petroleum fuel use. Based on the volume scenario
considered, the one time land use change impacts result in 448 million
metric tons of CO2-eq. emissions increase. There are, however, based on
the biofuel use replacing petroleum fuels, GHG reductions in each year.
When modeling the program as if all fuel volume changes occur in 2022,
and considering 100 years of emission impacts that are discounted by 2%
per year, we get an estimated total discounted NPV reduction in GHG
emissions of 6.8 billion tons over 100 years. Totaling the emissions
impacts over 30 years but assuming a 0% discount rate over this 30 year
period would result in an estimated total NPV reduction in GHG
emissions of 4.5 billion tons over 30 years.
This total NPV reduction can be converted into annual average GHG
reductions, which can be used for the calculations of the monetized GHG
benefits as shown in Section IX.C.4. This annualized value is based on
converting the lump sum present values described above into their
annualized equivalents. For this analysis we convert the NPV results
for the 100 year 2% discount rate into an annualized average such that
the NPV of the annualized average emissions will equal the NPV of the
actual emission stream over 100 years with a 2% discount rate. This
results in an annualized average emission reduction of approximately160
million metric tons of CO2-eq. emissions. A comparable value assuming
30 years of GHG emissions changes but not applying a discount rate to
those emissions results in an estimated annualized average emission
reduction of approximately 150 million metrics tons of CO2-eq.
emissions.
G. Effects of GHG Emission Reductions and Changes in Global Temperature
and Sea Level
1. Introduction
The reductions in CO2 and other GHGs associated with the
proposal will affect climate change projections. Because GHGs mix well
in the atmosphere and have long atmospheric lifetimes, changes in GHG
emissions will affect future climate for decades to centuries. One
common indicator of climate change is global mean surface temperature
and sea level rise. This section estimates the response in global mean
surface temperature projections to the estimated net global GHG
emissions reductions associated with the proposed rulemaking (See
Section VI.F for the estimated net reductions in global emissions over
time by GHG).
[[Page 25057]]
2. Estimated Projected Reductions in Global Mean Surface Temperatures
EPA estimated changes in projected global mean surface temperatures
to 2100 using the MiniCAM (Mini Climate Assessment Model) integrated
assessment model \320\ coupled with the MAGICC (Model for the
Assessment of Greenhouse-gas Induced Climate Change) simple climate
model.\321\ MiniCAM was used to create the globally and temporally
consistent set of climate relevant variables required for running
MAGICC. MAGICC was then used to estimate the change in the global mean
surface temperature over time. Given the magnitude of the estimated
emissions reductions associated with the proposed rule, a simple
climate model such as MAGICC is reasonable for estimating the climate
response.
---------------------------------------------------------------------------
\320\ MiniCAM is a long-term, global integrated assessment model
of energy, economy, agriculture and land use, that considers the
sources of emissions of a suite of greenhouse gases (GHG's), emitted
in 14 globally disaggregated global regions (i.e., U.S., Western
Europe, China), the fate of emissions to the atmosphere, and the
consequences of changing concentrations of greenhouse related gases
for climate change. MiniCAM begins with a representation of
demographic and economic developments in each region and combines
these with assumptions about technology development to describe an
internally consistent representation of energy, agriculture, land-
use, and economic developments that in turn shape global emissions.
Brenkert A, S. Smith, S. Kim, and H. Pitcher, 2003: Model
Documentation for the MiniCAM. PNNL-14337, Pacific Northwest
National Laboratory, Richland, Washington. For a recent report and
detailed description and discussion of MiniCAM, see Clarke, L., J.
Edmonds, H. Jacoby, H. Pitcher, J. Reilly, R. Richels, 2007.
Scenarios of Greenhouse Gas Emissions and Atmospheric
Concentrations. Sub-report 2.1A of Synthesis and Assessment Product
2.1 by the U.S. Climate Change Science Program and the Subcommittee
on Global Change Research. Department of Energy, Office of
Biological & Environmental Research, Washington, DC., USA, 154 pp.
\321\ MAGICC consists of a suite of coupled gas-cycle, climate
and ice-melt models integrated into a single framework. The
framework allows the user to determine changes in GHG
concentrations, global-mean surface air temperature and sea-level
resulting from anthropogenic emissions of carbon dioxide (CO2),
methane (CH4), nitrous oxide (N2O), reactive gases (e.g., CO,
NOX, VOCs), the halocarbons (e.g. HCFCs, HFCs, PFCs) and
sulfur dioxide (SO2). MAGICC emulates the global-mean temperature
responses of more sophisticated coupled Atmosphere/Ocean General
Circulation Models (AOGCMs) with high accuracy. Wigley, T.M.L. and
Raper, S.C.B. 1992. Implications for Climate and Sea-Level of
Revised IPCC Emissions Scenarios Nature 357, 293-300. Raper, S.C.B.,
Wigley T.M.L. and Warrick R.A. 1996. in Sea-Level Rise and Coastal
Subsidence: Causes, Consequences and Strategies J.D. Milliman, B.U.
Haq, Eds., Kluwer Academic Publishers, Dordrecht, The Netherlands,
pp. 11-45. Wigley, T.M.L. and Raper, S.C.B. 2002. Reasons for larger
warming projections in the IPCC Third Assessment Report J. Climate
15, 2945-2952.
---------------------------------------------------------------------------
EPA applied the estimated annual GHG emissions changes for the
proposal to the MiniCAM U.S. Climate Change Science Program (CCSP)
Synthesis and Assessment Product baseline emissions.\322\ Specifically,
the CO2, N2O, and CH4 annual emission
changes from 2022-2121 from Section VI.F were applied as net reductions
to the MiniCAM CCSP global baseline net emissions for each GHG. Post-
2121, we assumed no change in emissions from the baseline. This
assumption is more conservative than allowing the emissions reductions
to continue.
---------------------------------------------------------------------------
\322\ Clarke et al., 2007.
---------------------------------------------------------------------------
Table VI.G.2 provides our estimated reductions in projected global
mean surface temperatures and sea level associated with the proposed
increase in renewable fuels in 2022. To capture some of the uncertainty
in the climate system, we estimated the changes in projected
temperatures and sea level across the most current Intergovernmental
Panel on Climate Change (IPCC) range of climate sensitivities, 1.5
[deg]C to 6.0 [deg]C.\323\ To illustrate the time profile of the
estimated reductions in projected global mean surface temperatures and
sea level, we have also provided Figures VI.G.2-1 and VI.G.2-2.
---------------------------------------------------------------------------
\323\ In IPCC reports, equilibrium climate sensitivity refers to
the equilibrium change in the annual mean global surface temperature
following a doubling of the atmospheric equivalent carbon dioxide
concentration. The IPCC states that climate sensitivity is
``likely'' to be in the range of 2 [deg]C to 4.5 [deg]C and
described 3 [deg]C as a ``best estimate.'' The IPCC goes on to note
that climate sensitivity is ``very unlikely'' to be less than 1.5
[deg]C and ``values substantially higher than 4.5 [deg]C cannot be
excluded.'' IPCC WGI, 2007, Climate Change 2007--The Physical
Science Basis, Contribution of Working Group I to the Fourth
Assessment Report of the IPCC, http://www.ipcc.ch/.
Table VI.G.2-1--Estimated Reductions in Projected Global Mean Surface Temperature and Global Mean Sea Level From
Baseline in 2030, 2050, 2100, and 2200 for the Proposed Standard in 2022
----------------------------------------------------------------------------------------------------------------
Climate sensitivity
----------------------------------------------------------------
1.5 2 3 4.5 6
----------------------------------------------------------------------------------------------------------------
Change in global mean surface temperatures (degrees Celsius)
----------------------------------------------------------------------------------------------------------------
2030........................................... 0.000 0.000 -0.001 -0.001 -0.001
2050........................................... -0.001 -0.002 -0.002 -0.002 -0.003
2100........................................... -0.003 -0.004 -0.005 -0.006 -0.007
2200........................................... -0.003 -0.004 -0.006 -0.008 -0.009
----------------------------------------------------------------------------------------------------------------
Change in global mean sea level rise (centimeters)
----------------------------------------------------------------------------------------------------------------
2030........................................... -0.002 -0.002 -0.003 -0.003 -0.003
2050........................................... -0.012 -0.014 -0.017 -0.020 -0.022
2100........................................... -0.045 -0.052 -0.063 -0.074 -0.082
2200........................................... -0.077 -0.091 -0.114 -0.143 -0.172
----------------------------------------------------------------------------------------------------------------
The results in Table VI.G.2-1 and Figures VI.G.2-1 and VI.G.2-2
show small, but detectable, reductions in the global mean surface
temperature and sea level rise projections across all climate
sensitivities. Overall, the reductions are small relative to the IPCC's
``best estimate'' temperature increases by 2100 of 1.8 [deg]C to 4.0
[deg]C.\324\ Although IPCC does not issue ``best estimate'' sea level
rise projections, the model-based range across SRES scenarios is 18 to
59 cm by 2099.\325\ Both figures illustrate that the overall emissions
reductions can decrease projected annual temperature and sea level for
all climate sensitivities. This means that the distribution of
potential temperatures in any particular year is shifting down.
However, the shift is not uniform. The magnitude of the decrease is
larger for higher climate
[[Page 25058]]
sensitivities. Thus, the probability of a higher temperature or sea
level in any year is lowered more than the probability of a lower
temperature or sea level. For instance, in 2100, the reduction in
projected temperature for climate sensitivities of 3 and 6 is
approximately 65% and 140% greater than the reduction for a climate
sensitivity of 1.5. This difference grows over time, to approximately
80% and 185% by 2200. The same pattern appears in the reductions in the
sea level rise projections.\326\ Also noteworthy in Figures VI.G.2-1
and VI.G.2-2 is that the size of the decreases grows over time due to
the cumulative effect of a lower stock of GHGs in the atmosphere (i.e.,
concentrations).\327\
---------------------------------------------------------------------------
\324\ IPCC WGI, 2007. The baseline increases by 2100 from our
MiniCAM-MAGICC runs are 2 [deg]C to 5 [deg]C for global mean surface
temperature and 35 to 74 centimeters for global mean sea level.
\325\ ``Because understanding of some important effects driving
sea level rise is too limited, this report does not assess the
likelihood, nor provide a best estimate or an upper bound for sea
level rise.'' IPCC Synthesis Report, p. 45
\326\ In 2100, the reduction in projected sea level rise for
climate sensitivities of 3 and 6 is approximately 40% and 80%
greater than the reduction for a climate sensitivity of 1.5. This
difference grows over time, to approximately 50% and 120% by 2200.
\327\ For global average temperature after 2100, the growth in
the size of the decrease noticeable slows. This is because the
emissions changes associated with the policy were only estimated for
100 years. Note that even with emissions reductions stopping after
100 years, there continues to be a decrease in projected
temperatures due to reduced inertia in the climate system from the
earlier emissions reductions. However, unlike temperature, after
2100, the size of the decrease in sea level rise increases as the
projected reduction in warming has a continued effect on ice melt
and ocean thermal expansion.
---------------------------------------------------------------------------
The bottom line is that the risk of climate change is being
lowered, as the probabilities of any level of temperature increase and
sea level rise are reduced and the probabilities of the largest
temperature increases and sea level rise are reduced even more. For the
Final Rulemaking, we hope to more explicitly estimate the shapes of the
distributions and the estimated shifts in the shapes in response to the
Rulemakings.
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BILLING CODE 6560-50-C
VII. How Would the Proposal Impact Criteria and Toxic Pollutant
Emissions and Their Associated Effects?
A. Overview of Impacts
Today's proposal would influence the emissions of ``criteria''
pollutants (those pollutants for which a National Ambient Air Quality
Standard has been established), criteria pollutant precursors,\328\ and
air toxics, which may affect overall air quality and health. Emissions
would be affected by the processes required to produce and distribute
large volumes of biofuels proposed in today's action and the direct
effects of these fuels on vehicle and equipment emissions. As detailed
in Chapter 3 of the Draft Regulatory Impact Analysis (DRIA), we have
estimated emissions impacts of production and distribution-related
emissions using the life cycle analysis methodology described in
Section VI with emission factors for criteria and toxic emissions for
each stage of the life cycle, including agriculture, feedstock
transportation, and the production and distribution of biofuel;
included in this analysis are the impacts of reduced gasoline and
diesel refining as these fuels are displaced by biofuels. Emission
impacts of tailpipe and evaporative emissions for on and off road
sources have been estimated by incorporating ``per vehicle'' fuel
effects from recent research into mobile source emission inventory
estimation methods.
---------------------------------------------------------------------------
\328\ NOX and VOC are precursors to the criteria
pollutant ozone; we group them with criteria pollutants in this
chapter for ease of discussion.
---------------------------------------------------------------------------
For today's proposal we are presenting two sets of emission impacts
meant to present a range of the possible effects of ethanol blends on
light-duty vehicle emissions. This approach is carried forward from
analysis supporting the first RFS rule, which presented ``primary'' and
``sensitivity'' fuel effects cases differentiated by E10 effects on
cars and trucks. For this analysis we also analyze two fuel effects
scenarios, now termed ``less sensitive'' and ``more sensitive,''
referring to the sensitivity of car and truck exhaust emissions to both
E10 and E85 blends. As detailed in Section VII.C, the ``less
sensitive'' case does not apply any E10 effects to NOx or HC emissions
for later model year vehicles, or E85 effects for any pollutant, while
the ``more sensitive'' case assumes that later model year vehicles have
lower fuel sensitivity than earlier model vehicles. EPA and other
parties are in the midst of gathering additional data to help clarify
emissions impacts of ethanol on light-duty vehicles, and should be able
to reflect the new data for the final rule.
Analysis of criteria and toxic emission impacts was performed for
calendar year 2022, since this year reflects the full implementation of
today's proposal. Our 2022 projections account for projected growth in
vehicle travel and the effects of applicable emission and fuel economy
standards, including Tier 2 and Mobile Source Air Toxics (MSAT) rules
for cars and light trucks and recently finalized controls on spark-
ignited off-road engines. The impacts were analyzed relative to three
different reference case ethanol volumes, ranging from 3.64 to 13.2
billion gallons per year, in order to understand the impacts of today's
proposal in different contexts. To assess the total impact of the RFS
program, emissions were analyzed relative to the RFS1 rule base case of
3.64 billion gallons in 2004. To assess the impact of today's proposal
relative to the current mandated volumes, we analyzed impacts relative
to RFS1 mandate of 7.5 billion gallons of renewable fuel use by 2012,
which was estimated to include 6.7 billion gallons of ethanol.\329\ In
order to assess the impact of today's proposal relative to the level of
ethanol projected to already be in place by 2022, the AEO2007
projection of 13.2 billion gallons of
[[Page 25060]]
ethanol in 2022 was analyzed. For this analysis our modeling was based
on the differences between the AEO2007 reference case and the control
case; to generate impacts for the RFS1 base and mandated volumes we
simply scaled the modeled AEO2007-based impacts up according to the
larger increases in renewable fuel volumes relative to the other
reference cases. For the final rule we plan to directly model the RFS1
mandate reference case as well as the AEO2007 case.
---------------------------------------------------------------------------
\329\ For this analysis these RFS1 base and mandated ethanol
levels were assumed constant to 2022.
---------------------------------------------------------------------------
For the proposal we have only estimated the change in national
emission totals that would result from today's proposal. These totals
may not be a good indication of local or regional air quality and
health impacts. These results are aggregated across highly localized
sources, such as emissions from ethanol plants and evaporative
emissions from cars, and reflect offsets such as decreased emissions
from gasoline refineries. The location and composition of emissions
from these disparate sources may strongly influence the air quality and
health impacts of today's proposed action, and full-scale photochemical
air quality modeling is necessary to accurately assess this. These
localized impacts will be assessed in the final rule as discussed in
Section VII.D.
Our projected emission impacts for the ``less sensitive'' and
``more sensitive'' cases are shown in Table VII.A-1 and VII.A-2 for
2022. Shown relative to each reference case are the expected emission
changes for the U.S. in that year, and the percent contribution of this
impact relative to the total U.S. inventory. Overall we project the
proposed program will result in significant increases in ethanol and
acetaldehyde emissions--increasing the total U.S. inventories of these
pollutants by 30-40% in 2022 relative to the RFS1 mandate case. We
project more modest increases in NOx, HC, PM,
SO2, formaldehyde, and acrolein relative to the RFS1 mandate
case. We project a decrease in ammonia (NH3) emissions due
to reductions in livestock agricultural activity, CO (due to impacts of
ethanol on exhaust emissions from vehicles and nonroad equipment), and
benzene (due to displacement of gasoline with ethanol in the fuel
pool). As shown, the direction of changes for 1,3-butadiene and
naphthalene depends on whether it is the ``less sensitive'' or ``more
sensitive'' case.
Table VII.A-1--RFS2 ``Less Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 mandate AEO2007
-----------------------------------------------------------------------------------------------
Pollutant Percent of Percent of Percent of
Annual short total U.S. Annual short total U.S. Annual short total U.S.
tons inventory tons inventory tons inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOx..................................................... 312,400 2.8 274,982 2.5 195,735 1.7
HC...................................................... 112,401 1.0 72,362 0.6 -8,193 -0.07
PM10.................................................... 50,305 1.4 37,147 1.0 9,276 0.3
PM2.5................................................... 14,321 0.4 11,452 0.3 5,376 0.16
CO...................................................... -2,344,646 -4.4 -1,669,872 -3.1 -240,943 -0.4
Benzene................................................. -2,791 -1.7 -2,507 -1.5 -1,894 -1.1
Ethanol................................................. 210,680 36.5 169,929 29.4 83,761 14.5
1,3-Butadiene........................................... 344 2.9 255 2.1 65 0.5
Acetaldehyde............................................ 12,516 33.7 10,369 27.9 5,822 15.7
Formaldehyde............................................ 1,647 2.3 1,348 1.9 714 1.0
Naphthalene............................................. 5 0.03 3 0.02 -1 -0.01
Acrolein................................................ 290 5.0 252 4.4 174 3.0
SO2..................................................... 28,770 0.3 4,461 0.05 -47,030 -0.5
NH3..................................................... -27,161 -0.6 -27,161 -0.6 -27,161 -0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VII.A-2--RFS2 ``More Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 Mandate AEO2007
-----------------------------------------------------------------------------------------------
Pollutant Percent of Percent of Percent of
Annual short total U.S. Annual short total U.S. Annual short total U.S.
tons inventory tons inventory tons inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOx..................................................... 402,795 3.6 341,028 3.0 210,217 1.9
HC...................................................... 100,313 0.9 63,530 0.6 -15,948 -0.14
PM10.................................................... 46,193 1.3 33,035 0.9 5,164 0.15
PM2.5................................................... 10,535 0.3 7,666 0.2 1,589 0.05
CO...................................................... -3,779,572 -7.0 -3,104,798 -5.8 -1,675,869 -3.1
Benzene................................................. -5,962 -3.5 -5,494 -3.3 -4,489 -2.7
Ethanol................................................. 228,563 39.6 187,926 32.5 105,264 18.2
1,3-Butadiene........................................... -212 -1.8 -282 -2.4 -430 -3.6
Acetaldehyde............................................ 16,375 44.0 14,278 38.4 9,839 26.5
Formaldehyde............................................ 3,373 4.7 3,124 4.3 2,596 3.6
Naphthalene............................................. -175 -1.2 -178 -1.3 -187 -1.3
Acrolein................................................ 253 4.4 218 3.8 143 2.5
SO2..................................................... 28,770 0.3 4,461 0.05 -47,030 -0.5
NH3..................................................... -27,161 -0.6 -27,161 -0.6 -27,161 -0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 25061]]
The breakdown of these results by the fuel production/distribution
(``well-to-pump'' emissions) and vehicle and equipment (``pump-to-
wheel'') emissions is discussed in the following sections.
B. Fuel Production & Distribution Impacts of the Proposed Program
Fuel production and distribution emission impacts of the proposed
program were estimated in conjunction with the development of life
cycle GHG emission impacts and the GHG emission inventories discussed
in Section VI. These emissions are calculated according to the
breakdowns of agriculture, feedstock transport, fuel production, and
fuel distribution; the basic calculation is a function of fuel volumes
in the analysis year and the emission factors associated with each
process or subprocess. Additionally, the emission impact of displaced
petroleum is estimated, using the same domestic/import shares discussed
in Section VI above.
In general the basis for this life cycle evaluation was the
analysis conducted as part of the Renewable Fuel Standard (RFS1)
rulemaking, but enhanced significantly. While our approach for the RFS1
was to rely heavily on the ``Greenhouse Gases, Regulated Emissions, and
Energy Use in Transportation'' (GREET) model, developed by the
Department of Energy's Argonne National Laboratory (ANL), we are now
able to take advantage of additional information and models to
significantly strengthen and expand our analysis for this proposed
rule. In particular, the modeling of the agriculture sector was greatly
expanded beyond the RFS1 analysis, employing economic and agriculture
models to consider factors such as land-use impact, agricultural
burning, fertilizer, pesticide use, livestock, crop allocation, and
crop exports.
Other updates and enhancements to the GREET model assumptions
include updated feedstock energy requirements and estimates of excess
electricity available for sale from new cellulosic ethanol plants,
based on modeling by the National Renewable Energy Laboratory (NREL).
EPA also updated the fuel and feedstock transport emission factors to
account for recent EPA emission standards and modeling, such as the
diesel truck standards published in 2001 and the locomotive and
commercial marine standards finalized in 2008. Emission factors for new
corn ethanol plants continue to use the values developed for the RFS1
rule, which were based on data submitted by states for dry mill plants.
There are no new standards planned at this time that would offer any
additional control of emissions from corn or cellulosic ethanol plants.
In addition, GREET does not include air toxics or ethanol. Thus
emission factors for ethanol and the following air toxics were added:
benzene, 1,3-butadiene, formaldehyde, acetaldehyde, acrolein and
naphthalene.
Results of these calculations relative to each of the reference
cases for 2022 are shown in Table VII.B-1 for the criteria pollutants,
ammonia, ethanol and individual air toxic pollutants. It should be
noted that the impacts relative to the two RFS1 reference cases (3.64
and 6.7 billion gallons) rely on applying ethanol volume proportions to
the modeling results of the AEO2007 reference case (13.2 billion
gallons). Due to the complex interactions involved in projections in
the agricultural modeling, we did not attempt to adjust the
agricultural inputs of the AEO reference case for the other two
reference cases. So the fertilizer and pesticide quantities, livestock
counts, and total agricultural acres were the same for all three
reference cases. The agricultural modeling that had been done for the
RFS1 rule itself was much simpler and inconsistent with the new
modeling, so it would be inappropriate to use those estimates. Thus, we
plan to conduct additional agricultural modeling specifically for the
RFS1 mandate case prior to finalizing this rule.
The fuel production and distribution impacts of the proposed
program on VOC are mainly due to increases in emissions connected with
biofuel production, countered by decreases in emissions associated with
gasoline production and distribution as ethanol displaces some of the
gasoline. Increases in NOX, PM2.5, and
SOX are driven by combustion emissions from the substantial
increase in corn and cellulosic ethanol production. Ethanol plants
(corn and cellulosic) tend to have greater combustion emissions
relative to petroleum refineries on a per-BTU of fuel produced basis.
Increases in SOX emissions are primarily due to corn ethanol
production. Ammonia emissions are expected to decrease substantially
due to lower livestock counts, which more than offsets increased
ammonia from fertilizer use.
Ethanol vapor and most air toxic emissions associated with fuel
production and distribution are projected to increase. Relative to the
U.S. total reference case emissions with RFS1 mandate ethanol volumes,
increases of 10-20% for acetaldehyde and ethanol vapor are especially
significant because they are driven directly by the increased ethanol
production and distribution. Formaldehyde and acrolein increases are
smaller, on the order of 1-5%. Benzene emissions are estimated to
decrease by 1% due to decreased gasoline production. There are also
very small increases in 1,3-butadiene and decreases in naphthalene
relative to the U.S. total emissions.
Table VII.B-1--Fuel Production and Distribution Impacts in 2022 Relative to Each Reference Case
----------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 mandate AEO2007
--------------------------------------------------------------------------------
Pollutant Percent of Percent of Percent of
Annual total U.S. Annual total U.S. Annual total U.S.
short tons inventory short tons inventory short tons inventory
----------------------------------------------------------------------------------------------------------------
NOX............................ 241,041 2.1 222,732 2.0 183,951 1.6
HC............................. 77,295 0.7 46,702 0.4 -17,501 -0.2
PM10........................... 50,482 1.4 37,324 1.1 9,453 0.3
PM2.5.......................... 14,419 0.4 11,550 0.3 5,473 0.16
CO............................. 186,559 0.3 179,855 0.3 165,656 -0.5
Benzene........................ -1,670 -1.0 -1,686 -1.0 -1,719 -1.0
Ethanol........................ 115,187 19.9 100,134 17.3 68,379 11.8
1,3-Butadiene.................. 16 0.13 16 0.14 17 0.14
Acetaldehyde................... 7,460 20.1 6,680 18.0 5,029 13.5
Formaldehyde................... 877 1.2 800 1.1 638 0.9
Naphthalene.................... -6 -0.04 -5 -0.04 -4 -0.03
Acrolein....................... 278 4.8 244 4.2 174 3.0
[[Page 25062]]
SO2............................ 28,770 0.3 4,461 0.05 -47,030 -0.5
NH3............................ -27,161 -0.6 -27,161 -0.6 -27,161 -0.6
----------------------------------------------------------------------------------------------------------------
C. Vehicle and Equipment Emission Impacts of Fuel Program
The effects of the fuel program on vehicle and equipment emissions
are a direct function of the effects of these fuels on exhaust and
evaporative emissions from vehicles and off-road equipment, and
evaporation of fuel from portable containers. To assess these impacts
we conducted separate analyses to quantify the emission impacts of
additional E10 due to today's proposal on gasoline vehicles, nonroad
spark-ignited engines and portable fuel containers; E85 on cars and
light trucks; biodiesel on diesel vehicles; and increased refueling
events due to lower energy density of biofuels.\330\
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\330\ The impact of renewable diesel was not estimated for the
proposal; we expect little overall impact on criteria and toxic
emissions due to the relatively small volume change, and because
emission effects relative to conventional diesel are presumed to be
negligible.
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For the proposal we have analyzed inventory impacts for two fuel
effects scenarios to attempt to bound the potential impacts on ethanol
on gasoline-fueled vehicle exhaust emissions:
(1) ``Less Sensitive'': No exhaust VOC or NOX emission
impact on Tier 1 and later vehicles due to E10, and no impact due to
E85. This was termed the ``primary'' case in the RFS1 rule.
(2) ``More Sensitive'': VOC and NOX emission impacts due
to E10 based on limited test data from newer technology vehicles that
were analyzed as part of the RFS1 rule. This data showed a 7% reduction
in exhaust VOC emissions and an 8% increase in per-vehicle
NOX emissions for Tier 1 and later vehicles using E10
relative to E0. The E10 effects are consistent with the ``sensitivity''
case from the RFS1 rule. For RFS2 this case also includes E85 effects
reflecting significant increases in acetaldehyde, formaldehyde and
ethanol emissions, and reductions in PM and CO.
EPA and other parties are in the midst of gathering additional data
on the emission impacts of ethanol fuels on later model vehicles, which
we plan to consider in updating our final rule analysis.
We have also estimated the E10 effects on permeation emissions from
light-duty vehicles based on testing previously completed by the
Coordinating Research Council (CRC). Nonroad spark ignition (SI)
emission impacts of E10 were based on EPA's NONROAD model and show
trends similar to light duty vehicles. Biodiesel effects for this
analysis were based on a new analysis of recent biodiesel testing,
detailed in the DRIA, showing a 2% increase in NOX with a
20% biodiesel blend, a 16% decrease in PM, and a 14% decrease in HC.
These results essentially confirm the results of an earlier EPA
analysis.
Summarized vehicle and equipment emission impacts in 2022 are shown
in Table VII.C-1 and VII.C-2 for the ``less sensitive'' and ``more
sensitive'' cases. Table VII.C-3 shows the biodiesel contribution to
these impacts, which are comparatively small. While the two fuel effect
scenarios only differ with respect to exhaust emissions from cars and
trucks, the totals shown below reflect the net impacts from all mobile
sources, including car and truck evaporative emissions, off road
emissions, and portable fuel containers, using the same emissions
impacts for these sources in both cases. Additional breakdowns by
mobile source category can be found in Chapter 3 of the DRIA.
As shown in Tables VII.C-1 and VII.C-2, the vehicle and equipment
ethanol impacts vary widely between the two fuel effects cases. Under
the ``less sensitive'' case, CO and benzene are projected to decrease
in 2022 under today's proposal, while NOX, HC and the other
air toxics (except acrolein) are projected to increase due to the
impacts of E10. For the ``more sensitive'' case, NOX impacts
are higher and HC impacts lower due to the E10 effects on cars and
trucks, and the inclusion of E85 effects leads to larger reductions in
CO, benzene and 1,3-butadiene but more significant increases in
ethanol, acetaldehyde and formaldehyde. The impacts on acrolein
emissions in both cases, and on naphthalene in the ``more sensitive''
case depend on which reference case is considered, with small increases
relative to the RFS1 base and mandate cases and a decrease relative to
the AEO reference case.
Table VII.C-1--2022 Vehicle and Equipment ``Less Sensitive'' Case Emission Impacts by Fuel Type Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 mandate AEO2007
-----------------------------------------------------------------------------------------------
Pollutant Percent of Percent of Percent of
Annual short total U.S. Annual short total U.S. Annual short total U.S.
tons inventory tons inventory tons inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX..................................................... 71,359 0.6 52,250 0.5 11,784 0.11
HC...................................................... 35,106 0.3 25,659 0.2 9,308 0.08
PM10.................................................... -177 0.00 -177 0.00 -177 0.00
PM2.5................................................... -98 0.00 -98 0.00 -98 0.00
CO...................................................... -2,531,205 -4.7 -1,849,728 -3.4 -406,599 -0.8
Benzene................................................. -1,122 -0.7 -821 -0.5 -174 -0.1
Ethanol................................................. 95,493 16.5 69,795 12.1 15,383 2.7
1,3-Butadiene........................................... 328 2.7 238 2.0 48 0.4
Acetaldehyde............................................ 5,057 13.6 3,689 9.9 793 2.1
[[Page 25063]]
Formaldehyde............................................ 771 1.1 548 0.8 76 0.11
Naphthalene............................................. 10 0.07 8 0.05 3 0.02
Acrolein................................................ 12 0.2 8 0.14 -0.4 -0.01
SO2..................................................... 0 0.0 0 0.0 0 0.0
NH3..................................................... 0 0.0 0 0.0 0 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VII.C-2--2022 Vehicle and Equipment ``More Sensitive'' Case Emission Impacts by Fuel Type Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 base RFS1 mandate AEO2007
-----------------------------------------------------------------------------------------------
Pollutant Percent of Percent of Percent of
Annual short total U.S. Annual short total U.S. Annual short total U.S.
tons inventory tons inventory tons inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX..................................................... 161,754 1.4 118,295 1.1 26,266 0.2
HC...................................................... 23,018 0.2 16,828 0.15 1,553 0.01
PM10.................................................... -4,289 -0.12 -4,289 -0.12 -4,289 -0.12
PM2.5................................................... -3,884 -0.12 -3,884 -0.12 -3,884 -0.12
CO...................................................... -3,966,131 -7.4 -3,284,654 -6.1 -1,841,524 -3.4
Benzene................................................. -4,293 -2.6 -3,808 -2.3 -2,770 -1.6
Ethanol................................................. 113,376 19.6 87,792 15.2 36,886 6.4
1,3-Butadiene........................................... -228 -1.9 -298 -2.5 -446 -3.7
Acetaldehyde............................................ 8,915 24.0 7,598 20.4 4,809 12.9
Formaldehyde............................................ 2,497 3.5 2,324 3.2 1,958 2.7
Naphthalene............................................. -170 -1.2 -172 -1.2 -182 -1.3
Acrolein................................................ -25 -0.4 -27 -0.5 -31 -0.5
SO2..................................................... 0 0.0 0 0.0 0 0.0
NH3..................................................... 0 0.0 0 0.0 0 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VII.C-3--2022 Vehicle and Equipment Biodiesel Emission Impacts
Relative to All Reference Cases
[these impacts are included in Tables VII.C-1 and VII.C-2]
------------------------------------------------------------------------
Biodiesel
impacts
Pollutant ------------
Annual
short tons
------------------------------------------------------------------------
NOX........................................................ 418
HC......................................................... -753
PM10....................................................... -177
PM2.5...................................................... -98
CO......................................................... -1,275
Benzene.................................................... -9.4
Ethanol.................................................... 0.0
1,3-Butadiene.............................................. -5.1
Acetaldehyde............................................... -21
Formaldehyde............................................... -57
Naphthalene................................................ -0.12
Acrolein................................................... -2.7
SO2........................................................ 0.0
NH3........................................................ 0.0
------------------------------------------------------------------------
D. Air Quality Impacts
Although the purpose of this proposal is to implement the renewable
fuel requirements established by the Energy Independence and Security
Act (EISA) of 2007, this proposed rule would also impact emissions of
criteria and air toxic pollutants. We first present current levels of
PM2.5, ozone and air toxics and then discuss the national-
scale air quality modeling analysis that will be performed for the
final rule.
1. Current Levels of PM2.5, Ozone and Air Toxics
This proposal may have impacts on levels of PM2.5, ozone
and air toxics.\331\ Nationally, levels of PM2.5, ozone and
air toxics are declining.332 333 However, as of December 16,
2008, approximately 88 million people live in the 39 areas that are
designated as nonattainment for the 1997 PM2.5 National
Ambient Air Quality Standard (NAAQS) and approximately 132 million
people live in the 57 areas that are designated as nonattainment for
the 1997 8-hour ozone NAAQS. The 1997 PM2.5 NAAQS was
recently revised and the 2006 24-hour PM2.5 NAAQS became
effective on December 18, 2006. Area designations for the 2006 24-hour
PM2.5 NAAQS are expected to be promulgated in 2009 and
become effective 90 days after publication in the Federal Register. In
addition, the majority of Americans continue to be exposed to ambient
concentrations of air toxics at levels which have the potential to
cause adverse health effects.\334\ The levels of air toxics to which
people are exposed vary depending on where people live and work and the
kinds of activities in which they engage, as discussed in
[[Page 25064]]
detail in U.S. EPA's recent Mobile Source Air Toxics Rule.\335\
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\331\ The proposed standards may also impact levels of ambient
CO, a criteria pollutant (see Table VII.A-1 above for co-pollutant
emission impacts). For this analysis, however, we focus on the
proposal's impacts on ambient PM2.5 and ozone formation,
since CO is a relatively minor problem in comparison to some of the
other criteria pollutants. For example, as of August 15, 2008 there
are approximately 675,000 people living in 3 areas (which include 4
counties) that are designated as nonattainment for CO.
\332\ \\ U.S. EPA (2003) National Air Quality and Trends Report,
2003 Special Studies Edition. Office of Air Quality Planning and
Standards, Research Triangle Park, NC. Publication No. EPA 454/R-03-
005. http://www.epa.gov/air/airtrends/aqtrnd03/http://www.epa.gov/air/airtrends/aqtrnd03/.
\333\ \\ U.S. EPA (2007) Final Regulatory Impact Analysis:
Control of Hazardous Air Pollutants from Mobile Sources, Office of
Transportation and Air Quality, Ann Arbor, MI, Publication No.
EPA420-R-07-002. http://www.epa.gov/otaq/toxics.htm
\334\ U.S. Environmental Protection Agency (2007). Control of
Hazardous Air Pollutants from Mobile Sources; Final Rule. 72 FR
8434, February 26, 2007.
\335\ U.S. Environmental Protection Agency (2007). Control of
Hazardous Air Pollutants from Mobile Sources; Final Rule. 72 FR
8434, February 26, 2007.
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EPA has already adopted many emission control programs that are
expected to reduce ambient PM2.5, ozone and air toxics
levels. These control programs include the Small SI and Marine SI
Engine Rule (73 FR 59034, October 8, 2008), Locomotive and Commercial
Marine Rule (73 FR 25098, May 6, 2008), Mobile Source Air Toxics Rule
(72 FR 8428, February 26, 2007), Clean Air Interstate Rule (70 FR
25162, May 12, 2005), Clean Air Nonroad Diesel Rule (69 FR 38957, June
29, 2004), Heavy Duty Engine and Vehicle Standards and Highway Diesel
Fuel Sulfur Control Requirements (66 FR 5002, Jan. 18, 2001) and the
Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control
Requirements (65 FR 6698, Feb. 10, 2000). As a result of these
programs, the ambient concentration of air toxics, PM2.5 and
ozone in the future is expected to decrease.
2. Impacts of Proposed Standards on Future Ambient Concentrations of
PM2.5, Ozone and Air Toxics
The atmospheric chemistry related to ambient concentrations of
PM2.5, ozone and air toxics is very complex, making
predictions based solely on emissions changes extremely difficult. For
the final rule, a national-scale air quality modeling analysis will be
performed to analyze the impacts of the proposed standards on ambient
concentrations of PM2.5, ozone, and selected air toxics
(i.e., benzene, formaldehyde, acetaldehyde, ethanol, acrolein and 1,3-
butadiene). The length of time needed to prepare necessary inventory
and model updates has precluded us from performing air quality modeling
for this proposal.
The air quality modeling we plan to perform (described more
specifically below), will allow us to account for changes in the
spatial distribution of PM and PM precursors, and changes in VOC
speciation which could impact secondary PM formation. For example,
reductions in aromatics in gasoline may reduce ambient PM
concentrations by reducing secondary PM formation. Section 3.3 of the
Draft Regulatory Impact Analysis (DRIA) for this proposal contains more
information on aromatics and secondary aerosol formation.
In addition, air quality modeling will account for changes in fuel
type and spatial distribution of fuels that would change emissions of
ozone precursor species and thus could affect ozone concentrations.
Section 3.3 of the DRIA for this proposed rule provides more detail on
the atmospheric chemistry and potential changes in ozone formation due
to increased usage of ethanol fuels.
Section VII.A above presents projections of the changes in air
toxics emissions due to the proposed standards. The substantial
increase in emissions of ethanol and acetaldehyde suggests a likely
increase in ambient levels of acetaldehyde from both direct emissions
and secondary formation as ethanol breaks down in the atmosphere.
Formaldehyde and acrolein emissions would also increase somewhat, while
emissions of benzene and 1,3-butadiene would decrease as a result of
the proposed standards. Full-scale photochemical modeling is necessary
to provide the needed spatial and temporal detail to more completely
and accurately estimate the changes in ambient levels of these
pollutants.
For the final rule, EPA intends to use a 2005-based Community
Multi-scale Air Quality (CMAQ) modeling platform as the tool for the
air quality modeling. The CMAQ modeling system is a comprehensive
three-dimensional grid-based Eulerian air quality model designed to
estimate the formation and fate of oxidant precursors, primary and
secondary PM concentrations and deposition, and air toxics, over
regional and urban spatial scales (e.g., over the contiguous
U.S.).336 337 338 The CMAQ model is a well-known and well-
established tool and is commonly used by EPA for regulatory analyses,
for instance the recent ozone NAAQS proposal, and by States in
developing attainment demonstrations for their State Implementation
Plans.\339\ The CMAQ model (version 4.6) was peer-reviewed in February
of 2007 for EPA as reported in ``Third Peer Review of CMAQ Model,'' and
the peer review report for version 4.7 (described below) is currently
being finalized.\340\
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\336\ U.S. Environmental Protection Agency, Byun, D.W., and
Ching, J.K.S., Eds, 1999. Science algorithms of EPA Models-3
Community Multiscale Air Quality (CMAQ modeling system, EPA/600/R-
99/030, Office of Research and Development).
\337\ Byun, D.W., and Schere, K.L., 2006. Review of the
Governing Equations, Computational Algorithms, and Other Components
of the Models-3 Community Multiscale Air Quality (CMAQ) Modeling
System, J. Applied Mechanics Reviews, 59 (2), 51-77.
\338\ Dennis, R.L., Byun, D.W., Novak, J.H., Galluppi, K.J.,
Coats, C.J., and Vouk, M.A., 1996. The next generation of integrated
air quality modeling: EPA's Models-3, Atmospheric Environment, 30,
1925-1938.
\339\ U.S. EPA (2007). Regulatory Impact Analysis of the
Proposed Revisions to the National Ambient Air Quality Standards for
Ground-Level Ozone. EPA document number 442/R-07-008, July 2007.
\340\ Aiyyer, A., Cohan, D., Russell, A., Stockwell, W.,
Tanrikulu, S., Vizuete, W., Wilczak, J., 2007. Final Report: Third
Peer Review of the CMAQ Model. p. 23.
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CMAQ includes many science modules that simulate the emission,
production, decay, deposition and transport of organic and inorganic
gas-phase and particle-phase pollutants in the atmosphere. We intend to
use the most recent CMAQ version (version 4.7) which was officially
released by EPA's Office of Research and Development (ORD) in December
2008, and reflects updates to earlier versions in a number of areas to
improve the underlying science. These include (1) enhanced secondary
organic aerosol (SOA) mechanism to include chemistry of isoprene,
sesquiterpene, and aged in-cloud biogenic SOA in addition to terpene;
(2) improved vertical convective mixing; (3) improved heterogeneous
reaction involving nitrate formation; and (4) an updated gas-phase
chemistry mechanism, Carbon Bond 05 (CB05), with extensions to model
explicit concentrations of air toxic species as well as chlorine and
mercury. This mechanism, CB05-toxics, also computes concentrations of
species that are involved in aqueous chemistry and that are precursors
to aerosols. Section 3.3.3 of the DRIA for this proposal discusses SOA
formation and details about the improvements made to the SOA mechanism
within this recent release of CMAQ.
E. Health Effects of Criteria and Air Toxic Pollutants
1. Particulate Matter
a. Background
Particulate matter (PM) represents a broad class of chemically and
physically diverse substances. It can be principally characterized as
discrete particles that exist in the condensed (liquid or solid) phase
spanning several orders of magnitude in size. PM is further described
by breaking it down into size fractions. PM10 refers to
particles generally less than or equal to 10 micrometers ([mu]m) in
aerodynamic diameter. PM2.5 refers to fine particles,
generally less than or equal to 2.5 [mu]m in aerodynamic diameter.
Inhalable (or ``thoracic'') coarse particles refer to those particles
generally greater than 2.5 [mu]m but less than or equal to 10 [mu]m in
aerodynamic diameter. Ultrafine PM refers to particles less than 100
nanometers (0.1 [mu]m) in aerodynamic diameter. Larger particles tend
to be removed by the respiratory clearance mechanisms (e.g., coughing),
whereas
[[Page 25065]]
smaller particles are deposited deeper in the lungs.
Fine particles are produced primarily by combustion processes and
by transformations of gaseous emissions (e.g., SOX,
NOX and VOC) in the atmosphere. The chemical and physical
properties of PM2.5 may vary greatly with time, region,
meteorology and source category. Thus, PM2.5 may include a
complex mixture of different pollutants including sulfates, nitrates,
organic compounds, elemental carbon and metal compounds. These
particles can remain in the atmosphere for days to weeks and travel
hundreds to thousands of kilometers.
b. Health Effects of PM
Scientific studies show ambient PM is associated with a series of
adverse health effects. These health effects are discussed in detail in
the 2004 EPA Particulate Matter Air Quality Criteria Document (PM
AQCD), and the 2005 PM Staff Paper.341 342 Further
discussion of health effects associated with PM can also be found in
the DRIA for this rule.
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\341\ U.S. EPA (2004) Air Quality Criteria for Particulate
Matter (Oct. 2004), Volume I Document No. EPA600/P-99/002aF and
Volume II Document No. EPA600/P-99/002bF. This document is available
in Docket EPA-HQ-OAR-2005-0161.
\342\ U.S. EPA (2005) Review of the National Ambient Air Quality
Standard for Particulate Matter: Policy Assessment of Scientific and
Technical Information, OAQPS Staff Paper. EPA-452/R-05-005. This
document is available in Docket EPA-HQ-OAR-2005-0161.
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Health effects associated with short-term exposures (hours to days)
to ambient PM include premature mortality, increased hospital
admissions, heart and lung diseases, increased cough, adverse lower-
respiratory symptoms, decrements in lung function and changes in heart
rate rhythm and other cardiac effects. Studies examining populations
exposed to different levels of air pollution over a number of years,
including the Harvard Six Cities Study and the American Cancer Society
Study, show associations between long-term exposure to ambient
PM2.5 and both total and cardiovascular and respiratory
mortality.\343\ In addition, a reanalysis of the American Cancer
Society Study shows an association between fine particle and sulfate
concentrations and lung cancer mortality.\344\
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\343\ Dockery, D.W.; Pope, C.A. III: Xu, X.; et al. 1993. An
association between air pollution and mortality in six U.S. cities.
N Engl J Med 329:1753-1759.
\344\ Pope, C.A., III; Burnett, R.T.; Thun, M.J.; Calle, E.E.;
Krewski, D.; Ito, K.; Thurston, G.D. (2002) Lung cancer,
cardiopulmonary mortality, and long-term exposure to fine
particulate air pollution. J. Am. Med. Assoc. 287:1132-1141.
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2. Ozone
a. Background
Ground-level ozone pollution is typically formed by the reaction of
volatile organic compounds (VOC) and nitrogen oxides (NOX)
in the lower atmosphere in the presence of heat and sunlight. These
pollutants, often referred to as ozone precursors, are emitted by many
types of pollution sources, such as highway and nonroad motor vehicles
and engines, power plants, chemical plants, refineries, makers of
consumer and commercial products, industrial facilities, and smaller
area sources.
The science of ozone formation, transport, and accumulation is
complex.\345\ Ground-level ozone is produced and destroyed in a
cyclical set of chemical reactions, many of which are sensitive to
temperature and sunlight. When ambient temperatures and sunlight levels
remain high for several days and the air is relatively stagnant, ozone
and its precursors can build up and result in more ozone than typically
occurs on a single high-temperature day. Ozone can be transported
hundreds of miles downwind from precursor emissions, resulting in
elevated ozone levels even in areas with low local VOC or
NOX emissions.
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\345\ U.S. EPA Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). U.S. Environmental Protection
Agency, Washington, D.C., EPA 600/R-05/004aF-cF, 2006. This document
is available in Docket EPA-HQ-OAR-2005-0161. This document may be
accessed electronically at: http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_cd.html.
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b. Health Effects of Ozone
The health and welfare effects of ozone are well documented and are
assessed in EPA's 2006 Ozone Air Quality Criteria Document (ozone AQCD)
and 2007 Staff Paper.346 347 Ozone can irritate the
respiratory system, causing coughing, throat irritation, and/or
uncomfortable sensation in the chest. Ozone can reduce lung function
and make it more difficult to breathe deeply; breathing may also become
more rapid and shallow than normal, thereby limiting a person's
activity. Ozone can also aggravate asthma, leading to more asthma
attacks that require medical attention and/or the use of additional
medication. In addition, there is suggestive evidence of a contribution
of ozone to cardiovascular-related morbidity and highly suggestive
evidence that short-term ozone exposure directly or indirectly
contributes to non-accidental and cardiopulmonary-related mortality,
but additional research is needed to clarify the underlying mechanisms
causing these effects. In a recent report on the estimation of ozone-
related premature mortality published by the National Research Council
(NRC), a panel of experts and reviewers concluded that short-term
exposure to ambient ozone is likely to contribute to premature deaths
and that ozone-related mortality should be included in estimates of the
health benefits of reducing ozone exposure.\348\ Animal toxicological
evidence indicates that with repeated exposure, ozone can inflame and
damage the lining of the lungs, which may lead to permanent changes in
lung tissue and irreversible reductions in lung function. People who
are more susceptible to effects associated with exposure to ozone can
include children, the elderly, and individuals with respiratory disease
such as asthma. Those with greater exposures to ozone, for instance due
to time spent outdoors (e.g., children and outdoor workers), are also
of particular concern.
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\346\ U.S. EPA Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). U.S. Environmental Protection
Agency, Washington, DC, EPA 600/R-05/004aF-cF, 2006. This document
is available in Docket EPA-HQ-OAR-2005-0161. This document may be
accessed electronically at: http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_cd.html.
\347\ U.S. EPA (2007) Review of the National Ambient Air Quality
Standards for Ozone, Policy Assessment of Scientific and Technical
Information. OAQPS Staff Paper.EPA-452/R-07-003. This document is
available in Docket EPA-HQ-OAR-2005-0161. This document is available
electronically at: http:www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_sp.html..
\348\ National Research Council (NRC), 2008. Estimating
Mortality Risk Reduction and Economic Benefits from Controlling
Ozone Air Pollution. The National Academies Press: Washington, DC.
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The 2006 ozone AQCD also examined relevant new scientific
information that has emerged in the past decade, including the impact
of ozone exposure on such health effects as changes in lung structure
and biochemistry, inflammation of the lungs, exacerbation and causation
of asthma, respiratory illness-related school absence, hospital
admissions and premature mortality. Animal toxicological studies have
suggested potential interactions between ozone and PM, with increased
responses observed to mixtures of the two pollutants compared to either
ozone or PM alone. The respiratory morbidity observed in animal studies
along with the evidence from epidemiologic studies supports a causal
relationship between acute ambient ozone exposures and increased
respiratory-related emergency room visits and hospitalizations in the
warm season. In addition, there is
[[Page 25066]]
suggestive evidence of a contribution of ozone to cardiovascular-
related morbidity and non-accidental and cardiopulmonary mortality.
3. Carbon Monoxide
Carbon monoxide (CO) forms as a result of incomplete fuel
combustion. CO enters the bloodstream through the lungs, forming
carboxyhemoglobin and reducing the delivery of oxygen to the body's
organs and tissues. The health threat from CO is most serious for those
who suffer from cardiovascular disease, particularly those with angina
or peripheral vascular disease. Healthy individuals also are affected,
but only at higher CO levels. Exposure to elevated CO levels is
associated with impairment of visual perception, work capacity, manual
dexterity, learning ability and performance of complex tasks. Carbon
monoxide also contributes to ozone nonattainment since carbon monoxide
reacts photochemically in the atmosphere to form ozone.\349\ Additional
information on CO related health effects can be found in the Carbon
Monoxide Air Quality Criteria Document (CO AQCD).\350\
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\349\ U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide,
EPA/600/P-99/001F. This document is available in Docket EPA-HQ-OAR-
2005-0161.
\350\ U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide,
EPA/600/P-99/001F. This document is available in Docket EPA-HQ-OAR-
2005-0161.
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4. Air Toxics
The population experiences an elevated risk of cancer and noncancer
health effects from exposure to the class of pollutants known
collectively as ``air toxics.''\351\ Fuel combustion contributes to
ambient levels of air toxics that can include, but are not limited to,
acetaldehyde, acrolein, benzene, 1,3-butadiene, formaldehyde, ethanol,
naphthalene and peroxyacetyl nitrate (PAN). Acrolein, benzene, 1,3-
butadiene, formaldehyde and naphthalene have significant contributions
from mobile sources and were identified as national or regional risk
drivers in the 1999 National-scale Air Toxics Assessment (NATA).\352\
PAN, which is formed from precursor compounds by atmospheric processes,
is not assessed in NATA. Emissions and ambient concentrations of
compounds are discussed in the DRIA chapter on emission inventories and
air quality (Chapter 3).
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\351\ U. S. EPA. 1999 National-Scale Air Toxics Assessment.
http://www.epa.gov/ttn/atw/nata1999/risksum.html
\352\ U.S. EPA. 2006. National-Scale Air Toxics Assessment for
1999. http://www.epa.gov/ttn/atw/nata1999
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a. Acetaldehyde
Acetaldehyde is classified in EPA's IRIS database as a probable
human carcinogen, based on nasal tumors in rats, and is considered
toxic by the inhalation, oral, and intravenous routes.\353\
Acetaldehyde is reasonably anticipated to be a human carcinogen by the
U.S. DHHS in the 11th Report on Carcinogens and is classified as
possibly carcinogenic to humans (Group 2B) by the
IARC.354 355 EPA is currently conducting a reassessment of
cancer risk from inhalation exposure to acetaldehyde.
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\353\ U.S. EPA. 1991. Integrated Risk Information System File of
Acetaldehyde. Research and Development, National Center for
Environmental Assessment, Washington, DC. This material is available
electronically at.
\354\ U.S. Department of Health and Human Services National
Toxicology Program 11th Report on Carcinogens available at:
ntp.niehs.nih.gov/index.cfm?objectid=32BA9724-F1F6-975E-7FCE50709CB4C932.
\355\ International Agency for Research on Cancer (IARC). 1999.
Re-evaluation of some organic chemicals, hydrazine, and hydrogen
peroxide. IARC Monographs on the Evaluation of Carcinogenic Risk of
Chemical to Humans, Vol 71. Lyon, France.
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The primary noncancer effects of exposure to acetaldehyde vapors
include irritation of the eyes, skin, and respiratory tract.\356\ In
short-term (4 week) rat studies, degeneration of olfactory epithelium
was observed at various concentration levels of acetaldehyde
exposure.357 358 Data from these studies were used by EPA to
develop an inhalation reference concentration. Some asthmatics have
been shown to be a sensitive subpopulation to decrements in functional
expiratory volume (FEV1 test) and bronchoconstriction upon acetaldehyde
inhalation.\359\ The agency is currently conducting a reassessment of
the health hazards from inhalation exposure to acetaldehyde.
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\356\ U.S. EPA. 1991. Integrated Risk Information System File of
Acetaldehyde. This material is available electronically at http://www.epa.gov/iris/subst/0290.htm.
\357\ Appleman, L. M., R. A. Woutersen, V. J. Feron, R. N.
Hooftman, and W. R. F. Notten. 1986. Effects of the variable versus
fixed exposure levels on the toxicity of acetaldehyde in rats. J.
Appl. Toxicol. 6: 331-336.
\358\ Appleman, L.M., R.A. Woutersen, and V.J. Feron. 1982.
Inhalation toxicity of acetaldehyde in rats. I. Acute and subacute
studies. Toxicology. 23: 293-297.
\359\ Myou, S.; Fujimura, M.; Nishi, K.; Ohka, T.; and Matsuda,
T. 1993. Aerosolized acetaldehyde induces histamine-mediated
bronchoconstriction in asthmatics. Am. Rev. Respir. Dis. 148 (4 Pt
1): 940-3.
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b. Acrolein
EPA determined in 2003 that the human carcinogenic potential of
acrolein could not be determined because the available data were
inadequate. No information was available on the carcinogenic effects of
acrolein in humans and the animal data provided inadequate evidence of
carcinogenicity.\360\ The IARC determined in 1995 that acrolein was not
classifiable as to its carcinogenicity in humans.\361\
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\360\ U.S. EPA. 2003. Integrated Risk Information System File of
Acrolein. Research and Development, National Center for
Environmental Assessment, Washington, DC. This material is available
at http://www.epa.gov/iris/subst/0364.htm.
\361\ International Agency for Research on Cancer (IARC). 1995.
Monographs on the evaluation of carcinogenic risk of chemicals to
humans, Volume 63, Dry cleaning, some chlorinated solvents and other
industrial chemicals, World Health Organization, Lyon, France.
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Acrolein is extremely acrid and irritating to humans when inhaled,
with acute exposure resulting in upper respiratory tract irritation,
mucus hypersecretion and congestion. Levels considerably lower than 1
ppm (2.3 mg/m\3\) elicit subjective complaints of eye and nasal
irritation and a decrease in the respiratory rate.362 363
Lesions to the lungs and upper respiratory tract of rats, rabbits, and
hamsters have been observed after subchronic exposure to acrolein.
Based on animal data, individuals with compromised respiratory function
(e.g., emphysema, asthma) are expected to be at increased risk of
developing adverse responses to strong respiratory irritants such as
acrolein. This was demonstrated in mice with allergic airway disease by
comparison to non-diseased mice in a study of the acute respiratory
irritant effects of acrolein.\364\
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\362\ Weber-Tschopp, A.; Fischer, T.; Gierer, R.; et al. (1977)
Experimentelle reizwirkungen von Acrolein auf den Menschen. Int Arch
Occup Environ Hlth 40(2):117-130. In German.
\363\ Sim, V.M.; Pattle, R.E. (1957) Effect of possible smog
irritants on human subjects. J Am Med Assoc 165(15):1908-1913.
\364\ Morris J.B., Symanowicz P.T., Olsen J.E., et al. 2003.
Immediate sensory nerve-mediated respiratory responses to irritants
in healthy and allergic airway-diseased mice. J Appl Physiol
94(4):1563-1571.
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The intense irritancy of this carbonyl has been demonstrated during
controlled tests in human subjects, who suffer intolerable eye and
nasal mucosal sensory reactions within minutes of exposure.\365\
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\365\ Sim V.M., Pattle R.E. Effect of possible smog irritants on
human subjects. JAMA 165:1980-2010, 1957.
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c. Benzene
The EPA's IRIS database lists benzene as a known human carcinogen
(causing leukemia) by all routes of exposure, and concludes that
exposure is associated with additional health effects, including
[[Page 25067]]
genetic changes in both humans and animals and increased proliferation
of bone marrow cells in mice.366 367 368 EPA states in its
IRIS database that data indicate a causal relationship between benzene
exposure and acute lymphocytic leukemia and suggest a relationship
between benzene exposure and chronic non-lymphocytic leukemia and
chronic lymphocytic leukemia. The International Agency for Research on
Carcinogens (IARC) has determined that benzene is a human carcinogen
and the U.S. Department of Health and Human Services (DHHS) has
characterized benzene as a known human carcinogen.369 370
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\366\ U.S. EPA. 2000. Integrated Risk Information System File
for Benzene. This material is available electronically at http://www.epa.gov/iris/subst/0276.htm.
\367\ International Agency for Research on Cancer (IARC). 1982.
Monographs on the evaluation of carcinogenic risk of chemicals to
humans, Volume 29, Some industrial chemicals and dyestuffs, World
Health Organization, Lyon, France, p. 345-389.
\368\ Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry,
V.A. 1992. Synergistic action of the benzene metabolite hydroquinone
on myelopoietic stimulating activity of granulocyte/macrophage
colony-stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691-
3695.
\369\ International Agency for Research on Cancer (IARC). 1987.
Monographs on the evaluation of carcinogenic risk of chemicals to
humans, Volume 29, Supplement 7, Some industrial chemicals and
dyestuffs, World Health Organization, Lyon, France.
\370\ U.S. Department of Health and Human Services National
Toxicology Program, 11th Report on Carcinogens, available at: http://ntp.niehs.nih.gov/go/16183.
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A number of adverse noncancer health effects including blood
disorders, such as preleukemia and aplastic anemia, have also been
associated with long-term exposure to benzene.371 372 The
most sensitive noncancer effect observed in humans, based on current
data, is the depression of the absolute lymphocyte count in
blood.373 374 In addition, recent work, including studies
sponsored by the Health Effects Institute (HEI), provides evidence that
biochemical responses are occurring at lower levels of benzene exposure
than previously known.375 376 377 378 EPA's IRIS program has
not yet evaluated these new data.
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\371\ Aksoy, M. (1989). Hematotoxicity and carcinogenicity of
benzene. Environ. Health Perspect. 82:193-197.
\372\ Goldstein, B.D. (1988). Benzene toxicity. Occupational
medicine. State of the Art Reviews. 3:541-554.
\373\ Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E.
Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T. Smith, N. Titenko-
Holland, L.P. Zhang, W. Blot, S.N. Yin, and R.B. Hayes (1996)
Hematotoxicity among Chinese workers heavily exposed to benzene. Am.
J. Ind. Med. 29:236-246.
\374\ U.S. EPA (2002) Toxicological Review of Benzene (Noncancer
Effects). Environmental Protection Agency, Integrated Risk
Information System (IRIS), Research and Development, National Center
for Environmental Assessment, Washington DC. This material is
available electronically at http://www.epa.gov/iris/subst/0276.htm.
\375\ Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.;
Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; Rupa, D.;
Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; Winnik, M.; Kwok,
E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003) HEI Report 115,
Validation & Evaluation of Biomarkers in Workers Exposed to Benzene
in China.
\376\ Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et
al. (2002) Hematological changes among Chinese workers with a broad
range of benzene exposures. Am. J. Industr. Med. 42:275-285.
\377\ Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004)
Hematotoxicity in Workers Exposed to Low Levels of Benzene. Science
306:1774-1776.
\378\ Turtletaub, K.W. and Mani, C. (2003) Benzene metabolism in
rodents at doses relevant to human exposure from Urban Air. Research
Reports Health Effect Inst. Report No. 113.
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d. 1,3-Butadiene
EPA has characterized 1,3-butadiene as carcinogenic to humans by
inhalation.379 380 The IARC has determined that 1,3-
butadiene is a human carcinogen and the U.S. DHHS has characterized
1,3-butadiene as a known human carcinogen.381 382 There are
numerous studies consistently demonstrating that 1,3-butadiene is
metabolized into genotoxic metabolites by experimental animals and
humans. The specific mechanisms of 1,3-butadiene-induced carcinogenesis
are unknown; however, the scientific evidence strongly suggests that
the carcinogenic effects are mediated by genotoxic metabolites. Animal
data suggest that females may be more sensitive than males for cancer
effects associated with 1,3-butadiene exposure; there are insufficient
data in humans from which to draw conclusions about sensitive
subpopulations. 1,3-butadiene also causes a variety of reproductive and
developmental effects in mice; no human data on these effects are
available. The most sensitive effect was ovarian atrophy observed in a
lifetime bioassay of female mice.\383\
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\379\ U.S. EPA (2002) Health Assessment of 1,3-Butadiene. Office
of Research and Development, National Center for Environmental
Assessment, Washington Office, Washington, DC. Report No. EPA600-P-
98-001F. This document is available electronically at http://www.epa.gov/iris/supdocs/buta-sup.pdf.
\380\ U.S. EPA (2002) Full IRIS Summary for 1,3-butadiene (CASRN
106-99-0). Environmental Protection Agency, Integrated Risk
Information System (IRIS), Research and Development, National Center
for Environmental Assessment, Washington, DC, http://www.epa.gov/iris/subst/0139.htm.
\381\ International Agency for Research on Cancer (IARC) (1999)
Monographs on the evaluation of carcinogenic risk of chemicals to
humans, Volume 71, Re-evaluation of some organic chemicals,
hydrazine and hydrogen peroxide and Volume 97 (in preparation),
World Health Organization, Lyon, France.
\382\ U.S. Department of Health and Human Services (2005)
National Toxicology Program, 11th Report on Carcinogens, available
at: http://ntp.niehs.nih.gov/index.cfm?objectid=32BA9724-F1F6-975E-7FCE50709CB4C932.
\383\ Bevan, C.; Stadler, J.C.; Elliot, G.S.; et al. (1996)
Subchronic toxicity of 4-vinylcyclohexene in rats and mice by
inhalation. Fundam. Appl. Toxicol. 32:1-10.
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e. Ethanol
EPA is conducting an assessment of the cancer and noncancer effects
of exposure to ethanol, a compound which is not currently listed in
EPA's IRIS. A description of these effects to the extent that
information is available will be presented, as required by Section 1505
of EPAct, in a report to Congress on public health, air quality and
water resource impacts of fuel additives. We expect to release that
report in 2009.
Extensive data are available regarding adverse health effects
associated with the ingestion of ethanol while data on inhalation
exposure effects are sparse. As part of the IRIS assessment,
pharmacokinetic models are being evaluated as a means of extrapolating
across species (animal to human) and across exposure routes (oral to
inhalation) to better characterize the health hazards and dose-response
relationships for low levels of ethanol exposure in the environment.
The IARC has classified ``alcoholic beverages'' as carcinogenic to
humans based on sufficient evidence that malignant tumors of the mouth,
pharynx, larynx, esophagus, and liver are causally related to the
consumption of alcoholic beverages.\384\ The U.S. DHHS in the 11th
Report on Carcinogens also identified ``alcoholic beverages'' as a
known human carcinogen (they have not evaluated the cancer risks
specifically from exposure to ethanol), with evidence for cancer of the
mouth, pharynx, larynx, esophagus, liver and breast.\385\ There are no
studies reporting carcinogenic effects from inhalation of ethanol. EPA
is currently evaluating the available human and animal cancer data to
identify which cancer type(s) are the most relevant to an assessment of
risk to humans from a low-level oral and inhalation exposure to
ethanol.
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\384\ International Agency for Research on Cancer (IARC). 1988.
Monographs on the evaluation of carcinogenic risk of chemicals to
humans, Volume 44, Alcohol Drinking, World Health Organization,
Lyon, France.
\385\ U.S. Department of Health and Human Services. 2005.
National Toxicology Program 11th Report on Carcinogens available at:
ntp.niehs.nih.gov/index.cfm?objectid=32BA9724-F1F6-975E-7FCE50709CB4C932.
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Noncancer health effects data are available from animal studies as
well as epidemiologic studies. The epidemiologic data are obtained from
studies of alcoholic beverage
[[Page 25068]]
consumption. Effects include neurological impairment, developmental
effects, cardiovascular effects, immune system depression, and effects
on the liver, pancreas and reproductive system.\386\ There is evidence
that children prenatally exposed via mothers' ingestion of alcoholic
beverages during pregnancy are at increased risk of hyperactivity and
attention deficits, impaired motor coordination, a lack of regulation
of social behavior or poor psychosocial functioning, and deficits in
cognition, mathematical ability, verbal fluency, and spatial
memory.387 388 389 390 391 392 393 394 In some people,
genetic factors influencing the metabolism of ethanol can lead to
differences in internal levels of ethanol and may render some
subpopulations more susceptible to risks from the effects of ethanol.
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\386\ U.S. Department of Health and Human Services. 2000. 10th
Special Report to the U.S. Congress on Alcohol and Health. June
2000.
\387\ Goodlett CR, KH Horn, F Zhou. 2005. Alcohol teratogenesis:
mechanisms of damage and strategies for intervention. Exp. Biol.
Med. 230:394-406.
\388\ Riley EP, CL McGee. 2005. Fetal alcohol spectrum
disorders: an overview with emphasis on changes in brain and
behavior. Exp. Biol. Med. 230:357-365.
\389\ Zhang X, JH Sliwowska, J Weinberg. 2005. Prenatal alcohol
exposure and fetal programming: effects on neuroendocrine and immune
function. Exp. Biol. Med. 230:376-388.
\390\ Riley EP, CL McGee, ER Sowell. 2004. Teratogenic effects
of alcohol: a decade of brain imaging. Am. J. Med. Genet. Part C:
Semin. Med. Genet. 127:35-41.
\391\ Gunzerath L, V Faden, S Zakhari, K Warren. 2004. National
Institute on Alcohol Abuse and Alcoholism report on moderate
drinking. Alcohol. Clin. Exp. Res. 28:829-847.
\392\ World Health Organization (WHO). 2004. Global status
report on alcohol 2004. Geneva, Switzerland: Department of Mental
Health and Substance Abuse. Available: http://www.who.int/substance_abuse/publications/global_status_report_2004_overview.pdf.
\393\ Chen W-JA, SE Maier, SE Parnell, FR West. 2003. Alcohol
and the developing brain: neuroanatomical studies. Alcohol Res.
Health 27:174-180.
\394\ Driscoll CD, AP Streissguth, EP Riley. 1990. Prenatal
alcohol exposure comparability of effects in humans and animal
models. Neurotoxicol. Teratol. 12:231-238.
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f. Formaldehyde
Since 1987, EPA has classified formaldehyde as a probable human
carcinogen based on evidence in humans and in rats, mice, hamsters, and
monkeys.\395\ EPA is currently reviewing recently published
epidemiological data. For instance, research conducted by the National
Cancer Institute (NCI) found an increased risk of nasopharyngeal cancer
and lymphohematopoietic malignancies such as leukemia among workers
exposed to formaldehyde.396 397 NCI is currently performing
an update of these studies. A recent National Institute of Occupational
Safety and Health (NIOSH) study of garment workers also found increased
risk of death due to leukemia among workers exposed to
formaldehyde.\398\ Extended follow-up of a cohort of British chemical
workers did not find evidence of an increase in nasopharyngeal or
lymphohematopoietic cancers, but a continuing statistically significant
excess in lung cancers was reported.\399\ Recently, the IARC re-
classified formaldehyde as a human carcinogen (Group 1).\400\
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\395\ U.S. EPA (1987) Assessment of Health Risks to Garment
Workers and Certain Home Residents from Exposure to Formaldehyde,
Office of Pesticides and Toxic Substances, April 1987.
\396\ Hauptmann, M.; Lubin, J. H.; Stewart, P. A.; Hayes, R. B.;
Blair, A. 2003. Mortality from lymphohematopoietic malignancies
among workers in formaldehyde industries. Journal of the National
Cancer Institute 95: 1615-1623.
\397\ Hauptmann, M.; Lubin, J. H.; Stewart, P. A.; Hayes, R. B.;
Blair, A. 2004. Mortality from solid cancers among workers in
formaldehyde industries. American Journal of Epidemiology 159: 1117-
1130.
\398\ Pinkerton, L. E. 2004. Mortality among a cohort of garment
workers exposed to formaldehyde: an update. Occup. Environ. Med. 61:
193-200.
\399\ Coggon, D, EC Harris, J Poole, KT Palmer. 2003. Extended
follow-up of a cohort of British chemical workers exposed to
formaldehyde. J National Cancer Inst. 95:1608-1615.
\400\ International Agency for Research on Cancer (IARC). 2006.
Formaldehyde, 2-Butoxyethanol and 1-tert-Butoxypropan-2-ol. Volume
88. (in preparation), World Health Organization, Lyon, France.
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Formaldehyde exposure also causes a range of noncancer health
effects, including irritation of the eyes (burning and watering of the
eyes), nose and throat. Effects from repeated exposure in humans
include respiratory tract irritation, chronic bronchitis and nasal
epithelial lesions such as metaplasia and loss of cilia. Animal studies
suggest that formaldehyde may also cause airway inflammation--including
eosinophil infiltration into the airways. There are several studies
that suggest that formaldehyde may increase the risk of asthma--
particularly in the young.401 402
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\401\ Agency for Toxic Substances and Disease Registry (ATSDR).
1999. Toxicological profile for Formaldehyde. Atlanta, GA: U.S.
Department of Health and Human Services, Public Health Service.
http://www.atsdr.cdc.gov/toxprofiles/tp111.html.
\402\ WHO (2002) Concise International Chemical Assessment
Document 40: Formaldehyde. Published under the joint sponsorship of
the United Nations Environment Programme, the International Labour
Organization, and the World Health Organization, and produced within
the framework of the Inter-Organization Programme for the Sound
Management of Chemicals. Geneva.
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g. Naphthalene
Naphthalene is found in small quantities in gasoline and diesel
fuels. Naphthalene emissions have been measured in larger quantities in
both gasoline and diesel exhaust compared with evaporative emissions
from mobile sources, indicating it is primarily a product of
combustion. EPA released an external review draft of a reassessment of
the inhalation carcinogenicity of naphthalene based on a number of
recent animal carcinogenicity studies.\403\ The draft reassessment
completed external peer review.\404\ Based on external peer review
comments received, additional analyses are being undertaken. This
external review draft does not represent official agency opinion and
was released solely for the purposes of external peer review and public
comment. Once EPA evaluates public and peer reviewer comments, the
document will be revised. The National Toxicology Program listed
naphthalene as ``reasonably anticipated to be a human carcinogen'' in
2004 on the basis of bioassays reporting clear evidence of
carcinogenicity in rats and some evidence of carcinogenicity in
mice.\405\ California EPA has released a new risk assessment for
naphthalene, and the IARC has reevaluated naphthalene and re-classified
it as Group 2B: possibly carcinogenic to humans.\406\ Naphthalene also
causes a number of chronic non-cancer effects in animals, including
abnormal cell changes and growth in respiratory and nasal tissues.\407\
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\403\ U.S. EPA. 2004. Toxicological Review of Naphthalene
(Reassessment of the Inhalation Cancer Risk), Environmental
Protection Agency, Integrated Risk Information System, Research and
Development, National Center for Environmental Assessment,
Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0436.htm.
\404\ Oak Ridge Institute for Science and Education. (2004).
External Peer Review for the IRIS Reassessment of the Inhalation
Carcinogenicity of Naphthalene. August 2004. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=84403.
\405\ National Toxicology Program (NTP). (2004). 11th Report on
Carcinogens. Public Health Service, U.S. Department of Health and
Human Services, Research Triangle Park, NC. Available from: http://ntp-server.niehs.nih.gov.
\406\ International Agency for Research on Cancer (IARC).
(2002). Monographs on the Evaluation of the Carcinogenic Risk of
Chemicals for Humans. Vol. 82, Lyon, France.
\407\ U.S. EPA. 1998. Toxicological Review of Naphthalene,
Environmental Protection Agency, Integrated Risk Information System,
Research and Development, National Center for Environmental
Assessment, Washington, DC. This material is available
electronically at http://www.epa.gov/iris/subst/0436.htm.
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h. Peroxyacetyl Nitrate (PAN)
Peroxyacetyl nitrate (PAN) has not been evaluated by EPA's IRIS
program. Information regarding the potential carcinogenicity of PAN is
limited. As noted in the EPA air quality criteria
[[Page 25069]]
document for ozone and related photochemical oxidants, cytogenetic
studies indicate that PAN is not a potent mutagen, clastogen (a
compound that can cause breaks in chromosomes), or DNA-damaging agent
in mammalian cells either in vivo or in vitro. Some studies suggest
that PAN may be a weak bacterial mutagen at high concentrations much
higher than exist in present urban atmospheres.\408\
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\408\ U.S. EPA. 2006. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Ozone CD). Research Triangle Park, NC:
National Center for Environmental Assessment; report no. EPA/600/R-
05/004aF-cF.3v. page 5-78. Available at http://cfpub.epa.gov/ncea/.
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Effects of ground-level smog causing intense eye irritation have
been attributed to photochemical oxidants, including PAN.\409\ Animal
toxicological information on the inhalation effects of the non-ozone
oxidants has been limited to a few studies on PAN. Acute exposure to
levels of PAN can cause changes in lung morphology, behavioral
modifications, weight loss, and susceptibility to pulmonary infections.
Human exposure studies indicate minor pulmonary function effects at
high PAN concentrations, but large inter-individual variability
precludes definitive conclusions.\410\
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\409\ U.S. EPA. 2006. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). U.S. Environmental Protection
Agency, Washington, DC, EPA 600/R-05/004aF-cF. pages 5-63. This
document is available in Docket EPA-HQ-OAR-2005-0161. This document
may be accessed electronically at: http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_cd.html.
\410\ U.S. EPA. 2006. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). U.S. Environmental Protection
Agency, Washington, DC, EPA 600/R-05/004aF-cF. pages 5-78. This
document is available in Docket EPA-HQ-OAR-2005-0161. This document
may be accessed electronically at: http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_cd.html.
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i. Other Air Toxics
In addition to the compounds described above, other compounds in
gaseous hydrocarbon and PM emissions from vehicles will be affected by
today's proposed action. Mobile source air toxic compounds that will
potentially be impacted include ethylbenzene, polycyclic organic
matter, propionaldehyde, toluene, and xylene. Information regarding the
health effects of these compounds can be found in EPA's IRIS
database.\411\
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\411\ U.S. EPA. Integrated Risk Information System (IRIS)
database is available at: www.epa.gov/iris.
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F. Environmental Effects of Criteria and Air Toxic Pollutants
In this section we discuss some of the environmental effects of PM
and its precursors, such as visibility impairment, atmospheric
deposition, and materials damage and soiling, as well as environmental
effects associated with the presence of ozone in the ambient air, such
as impacts on plants, including trees, agronomic crops and urban
ornamentals, and environmental effects associated with air toxics.
1. Visibility
Visibility can be defined as the degree to which the atmosphere is
transparent to visible light.\412\ Airborne particles degrade
visibility by scattering and absorbing light. Visibility is important
because it has direct significance to people's enjoyment of daily
activities in all parts of the country. Individuals value good
visibility for the well-being it provides them directly, where they
live and work, and in places where they enjoy recreational
opportunities. Visibility is also highly valued in natural areas such
as national parks and wilderness areas and special emphasis is given to
protecting visibility in these areas. For more information on
visibility see the final 2004 PM AQCD as well as the 2005 PM Staff
Paper.413 414
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\412\ National Research Council, 1993. Protecting Visibility in
National Parks and Wilderness Areas. National Academy of Sciences
Committee on Haze in National Parks and Wilderness Areas. National
Academy Press, Washington, DC. This document is available in Docket
EPA-HQ-OAR-2005-0161. This book can be viewed on the National
Academy Press Web site at http://www.nap.edu/books/0309048443/html/.
\413\ U.S. EPA (2004) Air Quality Criteria for Particulate
Matter (Oct 2004), Volume I Document No. EPA600/P-99/002aF and
Volume II Document No. EPA600/P-99/002bF. This document is available
in Docket EPA-HQ-OAR-2005-0161.
\414\ U.S. EPA (2005) Review of the National Ambient Air Quality
Standard for Particulate Matter: Policy Assessment of Scientific and
Technical Information, OAQPS Staff Paper. EPA-452/R-05-005. This
document is available in Docket EPA-HQ-OAR-2005-0161.
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EPA is pursuing a two-part strategy to address visibility. First,
to address the welfare effects of PM on visibility, EPA has set
secondary PM2.5 standards which act in conjunction with the
establishment of a regional haze program. In setting this secondary
standard EPA has concluded that PM2.5 causes adverse effects
on visibility in various locations, depending on PM concentrations and
factors such as chemical composition and average relative humidity.
Second, section 169 of the Clean Air Act provides additional authority
to address existing visibility impairment and prevent future visibility
impairment in the 156 national parks, forests and wilderness areas
categorized as mandatory class I federal areas (62 FR 38680-81, July
18, 1997).\415\ In July 1999 the regional haze rule (64 FR 35714) was
put in place to protect visibility in mandatory class I federal areas.
Visibility can be said to be impaired in both PM2.5
nonattainment areas and mandatory class I federal areas.
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\415\ These areas are defined in CAA section 162 as those
national parks exceeding 6,000 acres, wilderness areas and memorial
parks exceeding 5,000 acres, and all international parks which were
in existence on August 7, 1977.
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2. Atmospheric Deposition
Wet and dry deposition of ambient particulate matter delivers a
complex mixture of metals (e.g., mercury, zinc, lead, nickel, aluminum,
cadmium), organic compounds (e.g., POM, dioxins, furans) and inorganic
compounds (e.g., nitrate, sulfate) to terrestrial and aquatic
ecosystems. The chemical form of the compounds deposited depends on a
variety of factors including ambient conditions (e.g., temperature,
humidity, oxidant levels) and the sources of the material. Chemical and
physical transformations of the particulate compounds occur in the
atmosphere as well as the media onto which they deposit. These
transformations in turn influence the fate, bioavailability and
potential toxicity of these compounds. Atmospheric deposition has been
identified as a key component of the environmental and human health
hazard posed by several pollutants including mercury, dioxin and
PCBs.\416\
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\416\ U.S. EPA (2000) Deposition of Air Pollutants to the Great
Waters: Third Report to Congress. Office of Air Quality Planning and
Standards. EPA-453/R-00-0005. This document is available in Docket
EPA-HQ-OAR-2005-0161.
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Adverse impacts on water quality can occur when atmospheric
contaminants deposit to the water surface or when material deposited on
the land enters a waterbody through runoff. Potential impacts of
atmospheric deposition to waterbodies include those related to both
nutrient and toxic inputs. Adverse effects to human health and welfare
can occur from the addition of excess particulate nitrate nutrient
enrichment, which contributes to toxic algae blooms and zones of
depleted oxygen, which can lead to fish kills, frequently in coastal
waters. Particles contaminated with heavy metals or other toxins may
lead to the ingestion of contaminated fish, ingestion of contaminated
water, damage to the marine ecology, and limits to recreational uses.
Several studies have been conducted in U.S. coastal waters and in the
Great Lakes Region in which the role of ambient PM deposition and
runoff is
[[Page 25070]]
investigated.417 418 419 420 421 In addition, the process of
acidification affects both freshwater aquatic and terrestrial
ecosystems. Acid deposition causes acidification of sensitive surface
waters. The effects of acid deposition on aquatic systems depend
largely upon the ability of the ecosystem to neutralize the additional
acid. As acidity increases, aluminum leached from soils and sediments,
flows into lakes and streams and can be toxic to both terrestrial and
aquatic biota. The lower pH concentrations and higher aluminum levels
resulting from acidification make it difficult for some fish and other
aquatic organisms to survive, grow, and reproduce.
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\417\ U.S. EPA (2004) National Coastal Condition Report II.
Office of Research and Development/Office of Water. EPA-620/R-03/
002. This document is available in Docket EPA-HQ-OAR-2005-0161.
\418\ Gao, Y., E.D. Nelson, M.P. Field, et al. 2002.
Characterization of atmospheric trace elements on PM2.5
particulate matter over the New York-New Jersey harbor estuary.
Atmos. Environ. 36: 1077-1086.
\419\ Kim, G., N. Hussain, J.R. Scudlark, and T.M. Church. 2000.
Factors influencing the atmospheric depositional fluxes of stable
Pb, 210Pb, and 7Be into Chesapeake Bay. J. Atmos. Chem. 36: 65-79.
\420\ Lu, R., R.P. Turco, K. Stolzenbach, et al. 2003. Dry
deposition of airborne trace metals on the Los Angeles Basin and
adjacent coastal waters. J. Geophys. Res. 108(D2, 4074): AAC 11-1 to
11-24.
\421\ \\ Marvin, C.H., M.N. Charlton, E.J. Reiner, et al. 2002.
Surficial sediment contamination in Lakes Erie and Ontario: A
comparative analysis. J. Great Lakes Res. 28(3): 437-450.
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Adverse impacts on soil chemistry and plant life have been observed
for areas heavily influenced by atmospheric deposition of nutrients,
metals and acid species, resulting in species shifts, loss of
biodiversity, forest decline and damage to forest productivity.
Potential impacts also include adverse effects to human health through
ingestion of contaminated vegetation or livestock (as in the case for
dioxin deposition), reduction in crop yield, and limited use of land
due to contamination. Research on effects of acid deposition on forest
ecosystems has come to focus increasingly on the biogeochemical
processes that affect uptake, retention, and cycling of nutrients
within these ecosystems. Decreases in available base cations from soils
are at least partly attributable to acid deposition. Base cation
depletion is a cause for concern because of the role these ions play in
acid neutralization and because calcium, magnesium and potassium are
essential nutrients for plant growth and physiology. Changes in the
relative proportions of these nutrients, especially in comparison with
aluminum concentrations, have been associated with declining forest
health.
The deposition of airborne particles can reduce the aesthetic
appeal of buildings and culturally important articles through soiling
and can contribute directly (or in conjunction with other pollutants)
to structural damage by means of corrosion or erosion.\422\ Particles
affect materials principally by promoting and accelerating the
corrosion of metals, by degrading paints, and by deteriorating building
materials such as concrete and limestone. Particles contribute to these
effects because of their electrolytic, hygroscopic, and acidic
properties and their ability to adsorb corrosive gases (principally
sulfur dioxide). The rate of metal corrosion depends on a number of
factors, including: The deposition rate and nature of the pollutant;
the influence of the metal protective corrosion film; the amount of
moisture present; variability in the electrochemical reactions; the
presence and concentration of other surface electrolytes; and the
orientation of the metal surface.
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\422\ \\ U.S. EPA (2005). Review of the National Ambient Air
Quality Standards for Particulate Matter: Policy Assessment of
Scientific and Technical Information, OAQPS Staff Paper. This
document is available in Docket EPA-HQ-OAR-2005-0161.
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3. Plant and Ecosystem Effects of Ozone
Ozone contributes to many environmental effects, with impacts to
plants and ecosystems being of most concern. Ozone can produce both
acute and chronic injury in sensitive species depending on the
concentration level and the duration of the exposure. Ozone effects
also tend to accumulate over the growing season of the plant, so that
even lower concentrations experienced for a longer duration have the
potential to create chronic stress on vegetation. Ozone damage to
plants includes visible injury to leaves and a reduction in food
production through impaired photosynthesis, both of which can lead to
reduced crop yields, forestry production, and use of sensitive
ornamentals in landscaping. In addition, the reduced food production in
plants and subsequent reduced root growth and storage below ground can
result in other, more subtle plant and ecosystems impacts. These
include increased susceptibility of plants to insect attack, disease,
harsh weather, interspecies competition and overall decreased plant
vigor. The adverse effects of ozone on forest and other natural
vegetation can potentially lead to species shifts and loss from the
affected ecosystems, resulting in a loss or reduction in associated
ecosystem goods and services. Last, visible ozone injury to leaves can
result in a loss of aesthetic value in areas of special scenic
significance like national parks and wilderness areas. The final 2006
Ozone Air Quality Criteria Document presents more detailed information
on ozone effects on vegetation and ecosystems.
4. Welfare Effects of Air Toxics
Fuel combustion emissions contribute to ambient levels of
pollutants that contribute to adverse effects on vegetation. PAN is a
well-established phytotoxicant causing visible injury to leaves that
can appear as metallic glazing on the lower surface of leaves with some
leafy vegetables exhibiting particular sensitivity (e.g., spinach,
lettuce, chard).423 424 425 PAN has been demonstrated to
inhibit photosynthetic and non-photosynthetic processes in plants and
retard the growth of young navel orange trees.426 427 In
addition to its oxidizing capability, PAN contributes nitrogen to
forests and other vegetation via uptake as well as dry and wet
deposition to surfaces. As noted in Section X, nitrogen deposition can
lead to saturation of terrestrial ecosystems and research is needed to
understand the impacts of excess nitrogen deposition experienced in
some areas of the country on water quality and ecosystems.\428\
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\423\ Nouchi I, S Toyama. 1998. Effects of ozone and
peroxyacetyl nitrate on polar lipids and fatty acids in leaves of
morning glory and kidney bean. Plant Physiol. 87:638-646.
\424\ Oka E, Y Tagami, T Oohashi, N Kondo. 2004. A physiological
and morphological study on the injury caused by exposure to the air
pollutant, peroxyacetyl nitrate (PAN), based on the quantitative
assessment of the injury. J Plant Res. 117:27-36.
\425\ Sun E-J, M-H Huang. 1995. Detection of peroxyacetyl
nitrate at phytotoxic level and its effects on vegetation in Taiwan.
Atmos. Env. 29:2899-2904.
\426\ Koukol J, WM Dugger, Jr., RL Palmer. 1967. Inhibitory
effect of peroxyacetyl nitrate on cyclic photophosphorylation by
chloroplasts from black valentine bean leaves. Plant Physiol.
42:1419-1422.
\427\ Thompson CR, G Kats. 1975. Effects of ambient
concentrations of peroxyacetyl nitrate on navel orange trees. Env.
Sci. Technol. 9:35-38.
\428\ \\ Bytnerowicz A, ME Fenn. 1995. Nitrogen deposition in
California forests: A Review. Environ. Pollut. 92:127-146.
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Volatile organic compounds (VOCs), some of which are considered air
toxics, have long been suspected to play a role in vegetation
damage.\429\ In laboratory experiments, a wide range of tolerance to
VOCs has been observed.\430\ Decreases in harvested seed pod weight
[[Page 25071]]
have been reported for the more sensitive plants, and some studies have
reported effects on seed germination, flowering and fruit ripening.
Effects of individual VOCs or their role in conjunction with other
stressors (e.g., acidification, drought, temperature extremes) have not
been well studied. In a recent study of a mixture of VOCs including
ethanol and toluene on herbaceous plants, significant effects on seed
production, leaf water content and photosynthetic efficiency were
reported for some plant species.\431\
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\429\ U.S. EPA. 1991. Effects of organic chemicals in the
atmosphere on terrestrial plants. EPA/600/3-91/001.
\430\ Cape JN, ID Leith, J Binnie, J Content, M Donkin, M
Skewes, DN Price, AR Brown, AD Sharpe. 2003. Effects of VOCs on
herbaceous plants in an open-top chamber experiment. Environ.
Pollut. 124:341-343.
\431\ Cape JN, ID Leith, J Binnie, J Content, M Donkin, M
Skewes, DN Price, AR Brown, AD Sharpe. 2003. Effects of VOCs on
herbaceous plants in an open-top chamber experiment. Environ.
Pollut. 124:341-343.
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Research suggests an adverse impact of vehicle exhaust on plants,
which has in some cases been attributed to aromatic compounds and in
other cases to nitrogen oxides.432 433 434 The impacts of
VOCs on plant reproduction may have long-term implications for
biodiversity and survival of native species near major roadways. Most
of the studies of the impacts of VOCs on vegetation have focused on
short-term exposure and few studies have focused on long-term effects
of VOCs on vegetation and the potential for metabolites of these
compounds to affect herbivores or insects.
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\432\ Viskari E-L. 2000. Epicuticular wax of Norway spruce
needles as indicator of traffic pollutant deposition. Water, Air,
and Soil Pollut. 121:327-337.
\433\ Ugrekhelidze D, F Korte, G Kvesitadze. 1997. Uptake and
transformation of benzene and toluene by plant leaves. Ecotox.
Environ. Safety 37:24-29.
\434\ Kammerbauer H, H Selinger, R Rommelt, A Ziegler-Jons, D
Knoppik, B Hock. 1987. Toxic components of motor vehicle emissions
for the spruce Pciea abies. Environ. Pollut. 48:235-243.
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VIII. Impacts on Cost of Renewable Fuels, Gasoline, and Diesel
We have assessed the impacts of the renewable fuel volumes required
by EISA on their costs and on the costs of the gasoline and diesel
fuels into which the renewable fuels will be blended. More details of
feedstock costs are addressed in Section X.A.
A. Renewable Fuel Production Costs
1. Ethanol Production Costs
a. Corn Ethanol
A significant amount of work has been done in the last decade
surveying and modeling the costs involved in producing ethanol from
corn in order 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 models developed and maintained by USDA. Their
work has been described in a peer-reviewed journal paper on cost
modeling of the dry-grind corn ethanol process, and compares well with
cost information found in surveys of existing plants.435 436
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\435\ Kwaitkowski, J.R., Macon, A., Taylor, F., Johnston, D.B.;
Industrial Crops and Products 23 (2006) 288-296.
\436\ Shapouri, H., Gallagher, P.; USDA's 2002 Ethanol Cost-of-
Production Survey (published July 2005).
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For our policy case scenario, we used corn prices of $3.34/bu in
2022 with corresponding DDGS prices of $139.78/ton (all 2006$). These
estimates are taken from agricultural economics modeling work done for
this proposal using the Forestry and Agricultural Sector Optimization
Model (see Section IX.A).
For natural gas-fired ethanol production producing dried co-product
(currently describes the largest fraction of the industry), in the
policy case corn feedstock minus DDGS sale credit represents about 57%
of the final per-gallon cost, while utilities, facility, and labor
comprise about 22%, 11%, and 4%, respectively. Thus, the cost of
ethanol production is most sensitive to the prices of corn and the
primary co-product, DDGS, and relatively insensitive to economy of
scale over the range of plant sizes typically seen (40-100 MMgal/yr).
We expect that several process fuels will be used to produce corn
ethanol (see DRIA Section 1.4), which are presented by their projected
2022 volume production share in Table VIII.A.1-1a and cost impacts for
each in Table VIII.A.1-1b.\437\ We request comment on the projected mix
of plant fuel sources in the future as well as the cost impacts of
various technologies.
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\437\ Projected fuel mix was taken from Mueller, S., Energy
Research Center at the University of Chicago; An Analysis of the
Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-
2030); cost estimates were derived from modifications to the USDA
process models. We are aware that the cost impacts of CHP are likely
overestimated here and will be revised in the final rulemaking.
Table VIII.A.1-1a--Projected 2022 Breakdown of Fuel Types Used To Estimate Production Cost of Corn Ethanol,
Percent Share of Total Production Volume
----------------------------------------------------------------------------------------------------------------
Fuel type Total by plant
---------------------------------------------------------------- type
Plant type ---------------
Biomass Coal (percent) Natural gas Biogas All fuels
(percent) (percent) (percent) (percent)
----------------------------------------------------------------------------------------------------------------
Coal/Biomass Boiler............. 11 0 .............. .............. 11
Coal/Biomass Boiler + CHP....... 10 4 .............. .............. 14
Natural Gas Boiler.............. .............. .............. 49 14 63
Natural Gas Boiler + CHP........ .............. .............. 12 .............. 12
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Total by Fuel Type.......... 21 4 61 14 100
----------------------------------------------------------------------------------------------------------------
Table VIII.A.1-1b--Projected 2022 Breakdown of Cost Impacts by Fuel Type Used in Estimating Production Cost of
Corn Ethanol, Dollars per Gallon Relative to Natural Gas Baseline
----------------------------------------------------------------------------------------------------------------
Fuel type Total by plant
---------------------------------------------------------------- type
Plant type ---------------
Biomass \a\ Coal Natural gas Biogas \b\ All fuels
----------------------------------------------------------------------------------------------------------------
Coal/Biomass Boiler............. -$0.02 -$0.02 .............. .............. ..............
Coal/Biomass Boiler + CHP....... +$0.14 +$0.14 .............. .............. ..............
Natural Gas Boiler.............. .............. .............. baseline +$0.00 ..............
[[Page 25072]]
Natural Gas Boiler + CHP........ .............. .............. +$0.16 .............. ..............
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Total by Fuel Type.......... .............. .............. .............. .............. $0.04
----------------------------------------------------------------------------------------------------------------
\a\ Assumes biomass has same plant-delivered cost as coal.
\b\ Assumes biogas has same plant-delivered cost as natural gas.
Based on energy prices from EIA's Annual Energy Outlook (AEO) 2008
baseline case ($53/bbl crude oil), we arrive at a production cost of
$1.49/gal. In the case of EIA's high price scenario ($92/bbl crude),
this figure increases by 6 cents per gallon. More details on the
ethanol production cost estimates can be found in Chapter 4 of the
DRIA. This estimate 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. The capital cost for a 65 MMgal/yr natural
gas fired dry mill plant is estimated at $89MM (this the projected
average size of such plants in 2022). Similarly, coal and biomass fired
plants were assumed to be 110 MGY in capacity, with an estimated
capital cost of $200MM.\438\ On average, ethanol produced in a facility
using coal or biomass as a primary energy source results in a per-
gallon cost $0.02/gal lower compared to production using natural gas.
---------------------------------------------------------------------------
\438\ Capital costs for a natural gas fired plant were taken
from USDA cost model; incremental costs to use coal as the primary
energy source were derived from conversations with ethanol plant
construction contractors.
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In this cost estimation work, we did not assume any pelletizing of
DDGS. Pelletizing is expected to improve ease of shipment to more
distant markets, which may become more important at the larger volumes
projected for the future. However, while many in industry are aware of
this technology, those we spoke with are not employing it in their
plants, and do not expect widespread use in the foreseeable future.
According to USDA's model, pelletizing adds $0.035/gal to the ethanol
production cost. We request comment on whether pelletizing should be
included in our program cost estimates.
In support of our biodiesel and renewable diesel volume feasibility
estimates, we included recovery of corn oil from distillers' grains
streams in our ethanol production cost estimates at a rate of 37% of
ethanol production by 2022.\439\ According to economic analyses done by
USDA based on the GS Cleantech corn oil extraction process, the capital
cost to install the system for a 50 MMgal/yr ethanol plant is
approximately $6 million. The system is capable of extracting about one
third of the corn oil entering the plant, and produces a low-quality
corn oil co-product stream. In our analysis, we assumed the value of
this additional co-product to be 70% that of soy oil (the same as
yellow grease, $0.27/lb), resulting in a credit per gallon of ethanol
of $0.04 for a 50 MMgal/yr plant operating such a system.
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\439\ Although some oil extraction may be done as front-end
fractionation of the kernel, we believe the majority will be
produced via separation from distillers' grains streams. For more
discussion of corn oil extraction and fractionation, see Chapter 4
of the DRIA.
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Note that the ethanol production cost given here does not account
for any subsidies on production or sale of ethanol, and is independent
of the market price of ethanol.
b. Cellulosic Ethanol
i. Feedstock Costs
Cellulosic Feedstock Costs
To estimate the cost of producing cellulosic biofuels, it was first
necessary to estimate the cost of harvesting, storing, processing and
transporting the feedstocks to the biofuel production facilities.
Ethanol or other cellulosic biofuels can be produced from crop residues
such as corn stover, wheat, rice, oat, and barley straw, sugar cane
bagasse, and sorghum, from other cellulosic plant matter such as forest
thinnings and forest-fuel removal, pulping residues, and from the
cellulosic portions of municipal solid waste (MSW). Currently, there
are no energy crops such as switchgrass nor short rotation woody crops
(SRWC poplars, etc.) grown specifically for energy production.
Our feedstock supply analysis projected that crop residue,
primarily corn stover, will be the most abundant of the cellulosic
feedstocks, comprising about 61% of the total biomass feedstock
inventory. Forest residues make up about 25% of the total, and MSW
makes up the remaining 14%. At present, there are no commercial sized
cellulosic ethanol plants in the U.S. Likewise, there are no
commercially proven, fully-integrated feedstock supply systems
dedicated to providing any of the feedstocks we mentioned to ethanol
facilities of any size, although certain biomass is harvested for other
purposes. For this reason, our feedstock cost estimates are projections
and not based on any existing market data.
Our feedstock costs include an additional preprocessing cost that
many other feedstock cost estimates do not include--thus our costs may
seem higher. We used biofuel plant cost estimates provided by NREL
which no longer includes the cost for finely grinding the feedstock
prior to feeding it to the biofuel plant. Thus, our feedstock costs
include an $11 per dry ton cost to account for the costs of this
grinding operation, regardless of whether this operation occurs in the
field or at the plant gate.
Crop Residue and Energy Crops
Crop residue harvest is currently a secondary harvest; that is they
are harvested or gathered only after the prime crop has been harvested.
In most northern areas, the harvest periods will be short due to the
onset of winter weather. In some cases, it may be necessary to gather a
full year's worth of residue within just a few weeks. Consequently, to
accomplish this hundreds of pieces of farm equipment will be required
for a few weeks each year to complete a harvest. Winter conditions in
the South make it somewhat easier to extend the harvest periods; in
some cases, it may be possible to harvest a residue on an as needed
basis.
During the corn grain harvest, generally only the cob and the
leaves above the cob are taken into the harvester. Thus, the stover
harvest would likely require some portion of the
[[Page 25073]]
standing-stalks be mowed or shredded, following which the entire
residue, including that discharged from the combine residue-spreader,
would need to be raked. Balers, likely a mix of large round and large
square balers, would follow the rakes. The bales would then be removed
from the field, usually to the field-side in the first operation of the
actual harvest, following which they would then be hauled to a
satellite facility for intermediate storage. For our analysis we
assumed that bales would then be hauled by truck and trailer to the
processing plant on an as needed basis.
The small grain straws (wheat, rice, oats, barley, sorghum) are cut
near the ground at the time of grain harvest and thus likely won't
require further mowing or shredding. They will likely need to be raked
into a windrow prior to baling. Because small grain straws have been
baled and stored for many years, we don't expect unusual requirements
for handling these residues. Their harvest and storage costs will
likely be less than those for corn stover, but their overall quantity
is much less than corn stover (corn stover makes up about 71% of all
the crop residues), so we don't expect their lower costs to have,
individually or collectively, a huge effect on the overall feedstock
costs. Thus, we project that for several years, the feedstock costs
will be largely a function of the cost to harvest, store, and haul corn
stover.
For the crop residues, we relied on the FASOM agricultural cost
model for farm harvesting and collection costs. FASOM estimates it
would cost $33 per dry ton to mow, rake, bale, and field haul the bales
and replace nutrients. We added $10 per dry ton as a farmer payment,
which we believe is a necessary reimbursement to farmers to cover their
costs associated with this additional harvest. Thus, $43 per dry ton
covers the cost of making the crop residue available at the farm gate.
This farm gate cost could be lower if new equipment is developed that
would allow the farmer to harvest the corn stover at the same time as
the corn. We also conducted our own independent analysis of the farm
gate feedstock costs for corn stover, and our farm gate cost estimate
for stover feedstock is very similar to FASOM's. For the steps involved
in moving the corn stover from the farm gate to the cellulosic ethanol
plant, we relied upon our own cost analysis. Our cost analysis
estimates that an additional $32 per dry ton would be required to haul
the bales to satellite storage, pay for the storage facilities, and
grind the residue. Because of the low density of corn stover and other
crop residues, we estimate that 60 or more secondary storage sites
would be necessary to minimize the combined transportation and storage
costs for a 100 million gallon per year plant. We estimated it would
cost about $14 per dry ton to haul the feedstock from the satellite
storage to the processing plant. Adding up all the costs, corn stover
is estimated to cost $88 per dry ton delivered to the cellulosic
biofuel plant. A more detailed discussion of our corn stover feedstock
cost analysis is contained in Chapter 4.1 of the DRIA.
Energy crops such as switchgrass and miscanthus would be harvested,
baled, stored and transported very similar to crop residues. Because of
their higher production density per acre, though, we would expect that
the ``farm gate'' costs to be slightly lower than crop residues (we
estimate the costs to be about $1 per dry ton lower). Also, the higher
production density would allow for fewer secondary storage facilities
compared to crop residue and a shorter transportation distance. For
example, we estimate that switchgrass would require less than 30
secondary storage facilities which would help to lower the feedstock
costs for a 100 million gallon per year plant compared to crop
residues. As a result the secondary storage and transportation costs
are estimated to be $9 per ton lower than crop residue such as corn
stover. Thus, we estimate that cellulosic feedstock costs sourced from
switchgrass would be about $78 per dry ton. Chapter 4.1 of the DRIA
contains a more in-depth discussion of the feedstock costs for energy
crops such as switchgrass.
Forestry Residue
Harvest and transport costs for woody biomass in its different
forms vary due to tract size, tree species, volumes removed, distance
to the wood-using/storage facility, terrain, road condition, and other
many other considerations. There is a significant variation in these
factors within the United States, so timber harvest and delivery
systems must be designed to meet constraints at the local level.
Harvesting costs also depend on the type of equipment used, season in
which the operation occurs, along with a host of other factors. Much of
the forest residue is already being harvested by logging operations, or
is available from milling operations. However, the smaller branches and
smaller trees proposed to be used for biofuel production are not
collected for their lumber so they are normally left behind. Thus, this
forest residue would have to be collected and transported out of the
forest, and then most likely chipped before transport to the biofuel
plant.
In general, most operators in the near future would be expected to
chip at roadside in the forest, blowing the chips directly into a chip
van. When the van is full it will be hauled to an end user's facility
and a new van will be moved into position at the chipper. The process
might change in the future as baling systems become economically
feasible or as roll-off containers are proven as a way to handle
logging slash. At present, most of the chipping for biomass production
is done in connection with forest thinning treatments as part of a
forest fire prevention strategy. The major problem associated with
collecting logging residues and biomass from small trees is handling
the material in the forest before it gets to the chipper. Specially-
built balers and roll-off containers offer some promise to reduce this
cost. Whether the material is collected from a forest thinning
operation or a commercial logging operation, chips from residues will
be dirty and will require screening or some type of filtration at the
end-user's facility.\440\
---------------------------------------------------------------------------
\440\ Personal Communication, Eini C. Lowell, Research
Scientist, USDA Forest Service.
---------------------------------------------------------------------------
Results from a study in South Georgia show that under the right
conditions, a small chipper could be added to a larger operation to
obtain additional chip production without adversely impacting roundwood
production, and that the chips could be produced from limbs and tops of
harvested trees at costs ranging from $11 per ton and up. Harvesting
understory (the layer formed by grasses, shrubs, and small trees under
the canopy of larger trees and plants) for use in making fuel chips was
estimated to be about $1 per ton more expensive.
Per-ton costs decrease as the volume chipped increases per acre.
Some estimates suggest that if no more than 10 loads of roundwood are
produced before a load of chips is made, that chipper-modified system
could break even. Cost projections suggest that removing only limbs and
tops may be marginal in terms of cost since one load of chips is
produced for about every 15 loads of roundwood.
Instead of conducting our own detailed cost estimate for making
forest residue chips available at the edge of the harvested forests, we
instead relied upon the expertise of the U.S. Forest Service. The U.S.
Forest Service provided us a cost curve for different categories of
forest residue, including logging residue, other removals (i.e.,
clearing trees for new building construction), timberland trimmings
[[Page 25074]]
(forest fire prevention strategy) and mill residues. They recommended
that we choose $45 per dry ton as the price point for our cost
analysis. This seemed reasonable since this price point was roughly the
same as the farm gate crop residue discussed above, and so we used this
price point for our analysis. Assuming that the wood chips would be
ground further in the field adds an additional $11 per dry ton to the
feedstock cost.
Delivery of woody biomass from the harvesting site to a conversion
facility, like delivery of more conventional forest products, accounts
for a significant portion of the delivered cost. In fact,
transportation of wood fiber (including hauling within the forest)
accounts for about 25 to 50% of the total delivered costs and highly
depends on fuel prices, haul distance, material moisture content, and
vehicle capacity and utilization. Also, beyond a certain distance,
transportation becomes the limiting factor and the costs become
directly proportional to haul distance.\441\ Based on our own cost
analysis, we anticipate that hauling woody biomass to plant will cost
about $14 per ton, for a total delivered price of about $70 per dry
ton. Chapter 4.1 of the DRIA contains a more detailed discussion on the
feedstock costs for forest residue.
---------------------------------------------------------------------------
\441\ Ashton, S.; B. Jackson; R. Schroeder. Cost Factors in
Harvesting and Transporting Woody Biomass, 2007. Module 4:
Introduction to Harvesting, Transportation, and Processing:: Fact
Sheet 4.7.
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Municipal Solid Waste
Millions of tons of municipal solid waste (MSW) continue to be
disposed of in landfills across the country, despite recent large gains
in waste reduction and diversion. The biomass fraction of this total
stream represents a potentially significant resource for renewable
energy (including electricity and biofuels). Because this waste
material is already being generated, collected and transported (it
would only need to be transported to a different location), its use is
likely to be less expensive than other cellulosic feedstocks. One
important difficulty facing those who plan to use MSW fractions for
fuel production is that in many places, even today, MSW is a mixture of
all types of wastes, including biomaterials such as animal fats and
grease, tin, iron, aluminum, and other metals, painted woods, plastics,
and glass. Many of these materials can't be used in biochemical and
thermochemical ethanol production, and, in fact, would inflate the
transportation costs, impede the operations at the cellulosic ethanol
plant and cause an expensive waste stream for biofuel producers.
Thus, accessing sorted MSW would likely be a requirement for firms
planning on using MSW for producing cellulosic biofuels. In a
confidential conversation, a potential producer who plans to use MSW to
produce ethanol indicated that their plant plans are based on obtaining
cellulosic biowaste which has already been sorted at the waste source
(e.g., at the curbside, where the refuse hauler picks up waste already
sorted by the generating home-owner or business). For example, in a
tract of homes, one refuse truck would pick up glass, plastic, and
perhaps other types of waste destined for a specific disposal depot,
whereas a different truck would follow to pick up wood, paper, and
other cellulosic materials to be hauled to a depot that supplies an
ethanol plant. However, only a small fraction of the MSW generated
today is sorted at the curbside.
Another alternative would be to sort the waste either at a sorting
facility, or at the landfill, prior to dumping. There are two prominent
options here. The first is that there is no sorting at the waste
creation site, the home or business, and thus a single waste stream
must be sorted at the facility. This operation would likely be done by
hand or by automated equipment at the facility. To do so by hand is
very labor intensive and somewhat slower than using an automated
system. In most cases the `by-hand' system produces a slightly cleaner
stream, but the high cost of labor usually makes the automated system
more cost-effective. Perhaps the best approach for low cost and a clean
stream is the combination of hand sorting with automated sorting.
The third option is a combination of the two which requires that
there is at least some sorting at the home or business which helps to
prevent contamination of the waste material, but then the final sorting
occurs downstream at a sorting site, or at the landfill.
We have little data and few estimates for the cost to sort MSW. One
estimate generated by our Office of Solid Waste for a combination of
mechanically and manually sorting a single waste stream downstream of
where the waste is generated puts the cost in the $20 to $30 per ton
range. There is a risk, though, that the waste stream could still be
contaminated and this would increase the cost of both transporting the
material and using this material at the biofuel plant due to the toxic
ash produced which would require disposal at a toxic waste facility. If
a less contaminated stream is desired it would probably require sorting
at the generation site--the home or business--which would likely be
more costly since many more people in society would then have to be
involved and special trucks would need to be used. Also, widespread
participation is difficult when a change in human behavior is required
as some may not be so willing to participate. Offering incentives could
help to speed the transition to curbside recycling (i.e., charging a
fee for nonsorted waste, or paying a small amount for sorted tree
trimmings and construction and demolition waste). Assuming that
curbside sorting is involved, at least in a minor way, total sorting
costs might be in the $30 to $40 per ton range. We request comment on
the costs incurred for sorting cellulosic material from the rest of MSW
waste.
These sorting costs would be offset by the cost savings for not
disposing of the waste material. Most landfills charge tipping fees,
the cost to dump a load of waste into a landfill. In the United States,
the national average nominal tipping fee increased fourfold from 1985
to 2000. The real tipping fee almost doubled, up from a national
average (in 1997 dollars) of about $12 per ton in 1985 to just over $30
in 2000. Equally important, it is apparent that the tipping fees are
much higher in densely populated regions and for areas along the U.S.
coast. For example, in 2004, the tipping fees were $9 per ton in Denver
and $97 per ton in Spokane. Statewide averages also varied widely, from
$8 a ton in New Mexico to $75 in New Jersey. Tipping fees ranged from
$21 to 98 per ton in 2006 for MSW and $18/ton to $120/ton for
construction and demolition waste. It is likely that the tipping fees
are highest for contaminated waste that requires the disposal of the
waste in more expensive waste sites that can accept the contaminated
waste as opposed to a composting site. However, this same contaminated
material would probably not be desirable to biofuel producers.
Presuming that only the noncontaminated cellulosic waste (yard
trimmings, building construction and demolition waste and some paper)
is collected as feedstocks for biofuel plants, the handling and tipping
fees are likely much lower, in the $30 per ton range.\442\
---------------------------------------------------------------------------
\442\ We plan on conducting a more thorough analysis of tipping
fees by waste type for the final rulemaking.
---------------------------------------------------------------------------
The avoidance of tipping fees, however, is a complex issue since
landfills are generally not owned by municipalities anymore. Both large
and small municipalities recognized their
[[Page 25075]]
inability to handle the new and complex solid waste regulations at a
reasonable cost. Only 38 out of the 100 largest cities own their own
landfills. To deal with the solid waste, large private companies built
massive amounts of landfill capacity. The economic incentive is for
private landfill operators to fill their landfills with garbage as
early as possible to pay off their capital investment (landfill site)
quickly. Also, the longer the landfill is operating the greater is its
exposure to liability due to leakages and leaching. Furthermore,
landfills can more cost-effectively manage the waste as the scale of
the landfill is enlarged. As a result, there are fewer landfills and
landfill owners, and an expansion of market share by large private
waste management firms, thus decreasing the leverage a biofuel producer
may have.\443\ Many waste management firms have been proactive by using
the waste material to produce biogas, another fuel type that would
qualify under RFS2. Yet other parties interested in procuring MSW are
waste-to-energy (WTE) facilities, which burn as much waste material as
possible to produce electricity. These three different interests may
compete for MSW for producing biofuels. This competition is desirable,
resulting in lower overall cost and the production of the most cost-
effective types of biofuels. We request comment on the costs avoided
for diverting cellulosic material from landfills.
---------------------------------------------------------------------------
\443\ Osamu Sakamoto, The Financial Feasibility Analysis of
Municipal Solid Waste to Ethanol Conversion, Michigan State
University, Plan B Master Research Paper in partial fulfillment of
the requirement for the degree of Master of Science, Department of
Agricultural Economics, 2004
---------------------------------------------------------------------------
Once the cellulosic biomass has been sorted from the rest of MSW,
it would have to be transported to the biofuels plant. Transporting is
different for MSW biomass compared to forest and crop residues. Forest
and crop residues are collected from forests and farms, which are both
rural sites, and transported to the biofuel plant which likely is
located at a rural site. The trucks which transport the forest and crop
residues can be large over-the-road trucks which can average moderate
speeds because of the lower amount of traffic that they experience.
Conversely, MSW is being collected throughout urban areas and would
have to transported through those urban areas to the plant site. If the
cellulosic biomass is being collected at curbside, it would likely be
collected in more conventional refuse trucks. If the plant is nearby,
then the refuse trucks could transport the cellulosic biomass directly
to the plant. However, if the plant is located far away from a portion
of the urban area, then the refuse trucks would probably have to be
offloaded to more conventional over-the-road trucks with sizable
trailers to make transport more cost-effective. We estimate that the
cost to transport the cellulosic biomass sourced from MSW to the
biofuel plant be $15 per ton.
A significant advantage of MSW over other cellulosic biomass is
that it can be generated year-round in many parts of the U.S. If a
steady enough stream of this material is available, then secondary
storage would not be necessary, thus avoiding the need to install
secondary storage. We assumed that no secondary storage costs would be
incurred for MSW-sourced cellulosic biomass.
The total costs for MSW-sourced cellulosic biomass is estimated to
be $30 -$40 per ton for sorting costs, a savings of $30 per ton for
tipping costs avoided, $15 per ton for transportation costs and $11 per
ton for grinding the cellulose to prepare it as a feedstock--resulting
in a total feedstock cost of $26 to $36 per ton. In our cost analysis,
we assumed an average cost of $31 per ton. Chapter 4.1 of the DRIA
contains a more detailed discussion of the feedstock costs for MSW.
Table VIII.A.1-2 below summarizes major cost components for each
cellulosic feedstock.
Table VIII.A.1-2--Summary of Cellulosic Feedstock Costs
[$53/ton crude oil costs]
----------------------------------------------------------------------------------------------------------------
Ag residue Switchgrass Forest residue MSW
----------------------------------------------------------------------------------------------------------------
60% of total feedstock 1% of total feedstock 25% of total feedstock 14% of total feedstock
----------------------------------------------------------------------------------------------------------------
Mowing, Raking, Baling, Hauling, Mowing, Raking, Baling, Harvesting, Hauling to Sorting, Contaminant
Nutrients and Farmer Payment $43/ton. Hauling, Nutrients and Forest Edge, Chipping Removal, Tipping Fees
Farmer Payment $42/ton. $45/ton. Avoided $0-$10/ton.
Hauling to Secondary Storage, Hauling to Secondary Grinding, Hauling to Grinding, Hauling to
Secondary Storage, Hauling to Plant Storage, Secondary Plant $25/ton. Plant $26/ton.
$45/ton. Storage, Hauling to
Plant $37/ton.
----------------------------------------------------------------------------------------------------------------
Total $88/ton.................... Total $77/ton.......... Total $70/ton.......... Total Avg $31/ton.
----------------------------------------------------------------------------------------------------------------
Weighting the cellulosic feedstock costs by their supply quantities
results in an average cellulosic feedstock cost of $71 per ton which we
used at the reference crude oil price of $53/bbl. We estimate that this
average cost increases to $76 per ton at the high crude oil price of
$92/bbl due to more expensive harvesting and transportation costs.
ii. Production Costs
In this section, we discuss the cost to biochemically and
thermochemically convert cellulosic feedstocks into fuel ethanol. At a
DOE sponsored workshop in 2005, a DOE biochemical expert commented that
the challenges of converting cellulosic biomass to ethanol are very
closely linked to solving the problems associated with both the
hydrolysis and the fermentation of the carbohydrates in the feedstocks.
He then stated that the resistance of cellulosic feedstock to
bioprocessing will remain the central problem and will likely be the
limiting factor in creating an economy based on cellulosic ethanol
production.\444\
---------------------------------------------------------------------------
\444\ Breaking the Biological Barriers to Cellulosic Ethanol: A
Joint Research Agenda, A Research Roadmap Resulting from the Biomass
to Biofuels Workshop Sponsored by the U.S. Department of Energy,
December 7-9, 2005, Rockville, Maryland; DOE/SC-0095, Publication
Date: June 2006
---------------------------------------------------------------------------
Notwithstanding the fact that all cellulosic biomass is made up of
some combination of cellulose, hemicellulose, lignin, and trace amounts
of other organic and inorganic chemicals and minerals, there are
significant differences among the molecular structures of different
plants. For example, a corn stalk is relatively lighter, more porous,
and much more flexible than a tree branch of similar diameter. The tree
branch (in most cases) is harder or denser and less porous throughout
the stem and the
[[Page 25076]]
outside or bark is less permeable and flexible.
These differences among the cellulosic feedstock plant structures,
e.g., density, rigidity, hardness, etc., suggest that different
conversion processes, namely biochemical and thermochemical may be
necessary to convert into ethanol as much of the available plant
material as possible. For example, if wood chips, e.g., poplar trees,
are to be treated biochemically, the chips must be reduced in size to
1-mm or less in order to increase the surface area for contact with
acid, enzymes, etc. Breaking up a 5-in stem to such small pieces would
consume a large amount of energy. On the other hand, processing corn
stover into cellulosic ethanol has a maximum size of up to 1.5 inches
(28 millimeters) in length because corn stover is so thin.\445\ By
comparison, the particle size requirement for a thermochemical process
is around 10-mm to 100-mm in diameter.\446\ Because of this, we believe
feedstocks such as corn stover, wheat and rice straw, and switchgrass
will likely be feedstocks for biochemical processes. Biochemical plants
will likely be constructed in those areas of the country where these
feedstocks are most abundant, e.g., the corn belt and upper Midwest. On
the other hand, thermochemical plants will likely be constructed in
those areas of the country where forest thinnings, forest fuel-removal
operations, lumber production, and paper mills are most predominant,
e.g., the South. Thermochemical or gasification units could be
constructed near starch or biochemical cellulosic plants in order to
take advantage of byproduct streams. We expect switchgrass (SG) will
preferentially be fed to biochemical units since it is similar to
straw, whereas short-rotation woody crops (SRWC) such as willows or
poplars will preferentially be fed to thermochemical units.
---------------------------------------------------------------------------
\445\ A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J.
Sheehan, and B. Wallace, National Renewable Energy Laboratory
(NREL); L. Montague, A. Slayton, and J. Lukas Harris Group, Seattle,
Washington, Ethanol Process Design and Economics Utilizing Co-
Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis for Corn
Stover; June 2002; NREL is a U.S. Department of Energy Laboratory
operated by Midwest Research Institute Battelle
Bechtel; Contract No. DE-AC36-99-GO10337.
\446\ Lin Wei, Graduate Research Assistant, Lester O. Pordesimo,
Assistant Professor, Willam D. Batchelor, Professor, Department of
Agricultural and Biological Engineering, Mississippi State
University, MS 39762, USA, Ethanol Production from Wood: Comparison
of Hydrolysis Fermentation and Gasification Biosynthesis, Paper
Number: 076036, Written for presentation at the 2007 ASABE Annual
International Meeting. Minneapolis Convention Center, Minneapolis,
MN, 17-20 June 2007.
---------------------------------------------------------------------------
Biochemically, it is much more difficult to convert cellulosic
plant matter into ethanol than it is to convert the starch from corn
grain into ethanol. Corn starch consists of long polysaccharide chains
that are weakly attracted to each other, quite flexible, and tend to
curl up to form tiny particle-like bundles. This loose, flexible
structure permits water and water-borne hydrolyzing enzymes to easily
penetrate the polymer during the process stage known as hydrolysis.
Once hydrolyzed, the corn starch sugar residues are easily fermentable.
The hydrolysis of cellulosic biomass is much more challenging.
Unlike starch, cellulosic plant matter is made up of three main
constituents: Cellulose, hemicellulose, lignin, and minor amounts of
various other organic and inorganic chemicals.
Cellulose, the major constituent, is a polymer made up of only
[beta]-linked glucose monosaccharides. This molecular arrangement
allows intra-molecular hydrogen bonds to develop within each monomer
and inter-molecular hydrogen bonds to develop between adjacent polymers
to form tight, rigid, strong, mostly straight polymer bundles that are
insoluble in water and resistant to chemical attack. The net result of
the structural characteristics makes cellulose much more difficult to
hydrolyze than is hemicellulose.
Hemicellulose contributes significantly to the total fermentable
sugars of the lignocellulosic biomass. Unlike cellulose, hemicellulose
is chemically heterogeneous and highly substituted. Compared to
cellulose, this branching renders it amorphous and relatively easy to
hydrolyze to its constituent sugars.\447\
---------------------------------------------------------------------------
\447\ Hans P. Blaschek, Professor and Thaddeus C. Ezeji,
Research Assistant, Department of Food Science and Human Nutrition,
University of Illinois, Urbana-Champaign. Science of Alternative
Feedstocks.
---------------------------------------------------------------------------
Lignin, the third principle component, is a complex, cross-linked
polymeric, high molecular weight substance derived principally from
coniferyl alcohol by extensive condensation polymerization. While
cellulose and hemicellulose contribute to the amount of fermentable
sugars for ethanol production, lignin is not so readily digestable, but
can be combusted to provide process energy in a biochemical plant or
used as feedstock to a thermochemical process.\448\
---------------------------------------------------------------------------
\448\ Glossary of Biomass Terms, National Renewable Energy
Laboratory, Golden, CO. http://www.nrel.gov/biomass/glossary.html.
---------------------------------------------------------------------------
Because of the complexities in digesting cellulosic biomass, the
residence time is longer to digest the cellulose and perform the
fermentation. Thus, the cellulosic plant capital costs are higher than
those of corn (starch) ethanol plants. However, because corn is a food
source with an intrinsic food value, corn ethanol's feedstock costs are
almost two times higher per ton (more than two times higher in the case
for cellulose from MSW) than the feedstocks of a cellulosic ethanol
plant. It is conceivable that depending on the cellulosic plant
technology which drives its capital and operating costs that cellulosic
ethanol plants' lower feedstock costs could offset its higher capital
costs resulting in lower production costs than corn-based ethanol.
The National Renewable Energy Laboratory has been evaluating the
state of biochemical cellulosic plant technology over the past decade
or so, and it has identified principal areas for improvement. In 1999,
it released its first report on the likely design concept for an nth
generation biochemical cellulosic ethanol plant which projected the
state of technology in some future year after the improvements were
adopted. In 2002, NREL released a follow-up report which delved deeper
into biochemical plant design in areas that it had identified in the
1999 report as deserving for additional research. Again, the 2002
report estimated the ethanol production cost for an nth generation
biochemical cellulosic ethanol plant. These reports not only helped to
inform policy makers on the likely capability and cost for
biochemically converting cellulose to ethanol, but it helped to inform
biochemical technology researchers on the most likely technology
improvements that could be incorporated into these plant designs.
To comply with the RFS 2 requirements, NREL assessed the likely
state of biochemical cellulosic plant technology over the years that
the RFS standard is being phased in. The specific years assessed by
NREL were 2010, 2015 and 2022. The year 2010 technology essentially
represents the status of today's biochemical cellulosic plants. The
year 2015 technology captures the expected near-term improvements
including the rapid improvements being made in enzyme technology. The
year 2022 technology captures the cost of mature biochemical cellulosic
plant technology. Table VIII.A.1-3 summarizes NREL's estimated and
projected production costs for biochemical cellulosic ethanol plant
technology in these three years
[[Page 25077]]
reflecting our average feedstock costs and adjusting the capital costs
to a 7 percent before tax rate of return.
Table VIII.A.1-3--Biochemical Cellulosic Ethanol Production Costs Provided by NREL
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Year technology................... 2010
2015
2022
Plant Size MMgal/yr............... 56
69
71
Capital Cost $MM.................. 232
220
199
----------------------------------------------------------------------------------------------------------------
$MM/yr c/gal $MM/yr c/gal $MM/yr c/gal
----------------------------------------------------------------------------------------------------------------
Capital Cost 7% ROI before taxes.. 25 46 24 35 22 31
Fixed Costs....................... 9 16 9 12 8 12
Feedstock Cost.................... 55 99 55 79 55 77
Other raw matl. costs............. 17 30 4 5 16 16
Enzyme Cost....................... 18 32 7 10 5 8
Enzyme nutrients.................. 8 14 2 3 2 2
Electricity....................... -6 -10 -7 -9 -12 -16
Waste disposal.................... 1 2 3 4 1 1
-----------------------------------------------------------------------------
Total Costs................... 127 229 96 139 84 131
----------------------------------------------------------------------------------------------------------------
NREL's projected improvements in production costs over time are
based on improved reaction biochemistry. Before discussing the expected
improvements in the reaction biochemistry, we will discuss the reaction
pathway for cellulosic biochemical.
There are two primary reaction steps in a biochemical cellulosic
ethanol plant. The first is hydrolysis. Hydrolysis breaks the
polysaccharides into their sugar residues. The pretreated slurry is fed
to a hydrolysis reactor; there may be multiple reactors, depending on
the desired production rate. Dilute sulfuric acid is used to hydrolyze,
primarily, the hemicellulose polysaccharides, xylan, mannan, arabinan,
and galactan, to produce the mixed sugars. Very little of the cellulose
polysaccharide, glucan, is hydrolyzed.
The second is saccharification and co-fermentation. Using a
cellulase enzyme cocktail, saccharification of the cellulose to glucose
occurs first at an elevated temperature to take advantage of increased
enzyme activity, which reduces the quantity of required enzyme as well
as the reaction time. Following cellulose saccharification, both the
glucose and xylose sugars are co-fermented. Although xylan, the
hemicellulose polysaccharide, is more easily hydrolyzed than glucan
(cellulose polysaccharides), the xylose sugar is more difficult to
ferment than the glucose sugar. Different microbes as well as different
residence times and process conditions are required for each.
Therefore, it may be necessary to separate the glucose and xylose
monomers before fermentation.
Because xylan can make up as much as 25% of plant matter it is
imperative that most of be available for ethanol production; the
economic viability of biochemically produced ethanol depends heavily
it. Good progress has been toward that end during the past few
years.\449\
---------------------------------------------------------------------------
\449\ Purdue yeast makes ethanol from agricultural waste more
effectively, Purdue News, June 28, 2004 http://www.purdue.edu/UNS/html4ever/2004/040628.Ho.ethanol.html.
---------------------------------------------------------------------------
Also during the past few years, researchers have been developing
ways to combine saccharification and fermentation into a single step
through the use of enzyme/microbe cocktails. DOE and the National
Renewable Energy Laboratory (NREL) have also supported research into
more efficient, less costly enzymes for SSF. With their support, a less
expensive, more efficient enzyme cocktail for cellulosic biomass
fermentation has been developed.\450\ Others have also reported some
success in co-fermenting glucose and xylose.\451\
---------------------------------------------------------------------------
\450\ GENENCOR LAUNCHES FIRST EVER COMMERCIAL ENZYME PRODUCT FOR
CELLULOSIC ETHANOL, ROCHESTER, NY, World-Wire, October 22, 2007
Copyright[sscopy] 2007. All rights reserved. World-Wire is a
resource provided by Environment News Service. http://world-wire.com/news/0710220001.html.
\451\ Ali Mohagheghi, Kent Evans, Yat-Chen Chou, and Min Zhang,
Biotechnology Division for Fuels and Chemicals, National Renewable
Energy Laboratory, Golden, CO 80401, Co-fermentation of Glucose,
Xylose, and Arabinose by Genomic DNA-Integrated Xylose/Arabinose
Fermenting Strain of Zymomonas mobilis AX101, Applied Biochemistry
and Biotechnology Vols. 98-100, 2002, Copyright[sscopy] 2002 by
Humana Press Inc., All rights of any nature whatsoever reserved.
---------------------------------------------------------------------------
As the biochemical enzymatic pathway is streamlined using more
cost-effective enzymes, and as these enzymes can more comprehensively
saccarify and ferment the cellulose, the conversion fraction of the
cellulose to ethanol will increase and the conversion time will
decrease. An important benefit for these efficiency improvements is
that the number and size of reaction vessels decrease, leading to lower
capital costs and lower fixed operating costs. It is also estimated
that less nutrients would be needed to maintain the enzymes reactivity.
Because the production volume of ethanol will increase relative to the
quantity of feedstock, it lowers the operating costs per gallon of
ethanol. Between these various effects, the per-gallon costs for
producing cellulosic ethanol through the biochemical pathway are
expected to decrease dramatically. It is through these expected
improvements that NREL has estimated reduced production costs for
biochemical cellulosic ethanol plants.
Thermochemical conversion is another reaction pathway which exists
for converting cellulose to ethanol. Thermochemical technology is based
on the heat and pressure-based gasification or pyrolysis of nearly any
biomass feedstock, including those we've highlighted as likely
biochemical feedstocks. The syngas is converted into mixed alcohols,
hydrocarbon fuels, chemicals, and power. A thermochemical unit can also
complement a biochemical processing plant to enhance the economics of
an integrated biorefinery by converting lignin-rich, non-fermentable
material left over from high-starch or cellulosic. NREL has not yet
estimated the cost of thermochemically converting cellulose to ethanol,
so we did not include a cost estimate using this potential conversion
pathway in our analysis and based our cost analysis entirely on the
biochemical route.\452\ However, one
[[Page 25078]]
report estimated that the costs are similar for converting cellulose to
ethanol either through either the biochemical or thermochemical routes.
Thus, we believe that our cellulosic ethanol costs are representative
of both technologies. In Section VIII.A.3 below, we discuss the costs
for a thermochemical route for producing diesel fuel, often referred to
as biomass-to-liquids (BTL) process.
---------------------------------------------------------------------------
\452\ NREL has authored a thermochemical report: Phillips, S
Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol
Synthesis of Lignocellulosic Biomass; April, 2007, which does
provide a cost estimate. However, this report only hypothesized how
a thermochemical ethanol plant could achieve production costs at $1
per gallon, and thus it could not be relied upon for any part of our
real-world program cost analysis.
---------------------------------------------------------------------------
c. Imported Sugarcane Ethanol
We based our imported ethanol fuel costs on cost estimates of
sugarcane ethanol in Brazil. Generally, ethanol from sugarcane produced
in developing countries with warm climates is much cheaper to produce
than ethanol from grain or sugar beets. This is due to favorable
growing conditions, relatively low cost feedstock and energy inputs,
and other cost reductions gained from years of experience.
As discussed in Chapter 4 of the DRIA, our literature search of
production costs for sugar cane ethanol in Brazil indicates that
production costs tend to range from as low as $0.57 per gallon of
ethanol to as high as $1.48 per gallon of ethanol. This large range for
estimating production costs is partly due to the significant variations
over time in exchange rates, costs of sugarcane and oil products, etc.
For example, earlier estimates may underestimate current crude and
natural gas costs which influence the cost of feedstock as well as
energy costs at the plant. Another possible difference in production
cost estimates is whether or not the estimates are referring to hydrous
or anhydrous ethanol. Costs for anhydrous ethanol (for blending with
gasoline) are typically several cents per gallon higher than hydrous
ethanol (for use in dedicated ethanol vehicles in Brazil).\453\ It is
not entirely clear from the majority of studies whether reported costs
are for hydrous or anhydrous ethanol. Yet another difference could be
the slate of products the plant is producing, for example, future
plants may be dedicated ethanol facilities while others involve the
production of both sugar and ethanol in the same facility. Due to
economies of scale, production costs are also typically smaller per
gallon for larger facilities.
---------------------------------------------------------------------------
\453\ International Energy Agency (IEA), ``Biofuels for
Transport: An International Perspective,'' 2004.
---------------------------------------------------------------------------
The study by OECD (2008) entitled ``Biofuels: Linking Support to
Performance'', appears to provide the most recent and detailed set of
assumptions and production costs. As such, our estimate of sugarcane
production costs primarily relies on the assumptions made for the
study, which are shown in Table VIII.A.1-4. The estimate assumes an
ethanol-dedicated mill and is based off an internal rate of return of
12%, a debt/equity ratio of 50% with an 8% interest rate and a selling
of surplus power at $57 per MWh.
Table VIII.A.1-4--Cost of Production in a Standard Ethanol Project in Brazil
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Sugarcane Productivity...................... 71.5 t/ha.
Sugarcane Consumption....................... 2 million tons/year.
Harvesting days............................. 167.
Ethanol productivity........................ 85 liters/ton (22.5 gal/ton).
Ethanol production.......................... 170 million liters/year (45 MGY).
Surplus power produced...................... 40 kWh/ton sugarcane.
Investment cost in mill..................... USD 97 million.
Investment cost for sugarcane production.... USD 36 million.
O & M (Operating & Maintenance) costs....... $0.26/gal.
Sugarcane costs............................. $0.64/gal.
Capital costs............................... $0.49/gal.
-------------------------------------------------------------------
Total production costs.................. $1.40/gal.
----------------------------------------------------------------------------------------------------------------
The estimate above is based on the costs of producing ethanol in
Brazil on average, today. However, we are interested in how the costs
of producing ethanol will change by the year 2022. Although various
cost estimates exist, analysis of the cost trends over time shows that
the cost of producing ethanol in Brazil has been steadily declining due
to efficiency improvements in cane production and ethanol conversion
processes. Between 1980 and 1998 (total span of 19 years) ethanol cost
declined by approximately 30.8%.\454\ This change in the cost of
production over time in Brazil is known as the ethanol cost ``Learning
Curve''.
---------------------------------------------------------------------------
\454\ Goldemberg, J. as sited in Rothkopf, Garten, ``A Blueprint
for Green Energy in the Americas,'' 2006.
---------------------------------------------------------------------------
The change in ethanol costs will depend on the likely productivity
gains and technological innovations that can be made in the future. As
the majority of learning may have already occurred, it is likely that
the decline in sugarcane ethanol costs will be less drastic as the
production process and cane practices have matured. This is in contrast
to younger technologies such as those used to produce cellulosic
biofuels which could likely have larger cost reductions over the same
period of time. In fact, there are few perspectives for substantial
efficiency gains with the sugarcane processing technology. Industrial
efficiency gains are already at about 85% and are expected to increase
to 90% in 2015.\455\ Most of the productivity growth is expected to
come from sugarcane production, where yields are expected to grow from
the current 70 tons/ha, to 96 tons/ha in 2025.\456\ Sugarcane quality
is also expected to improve, with sucrose content growing from 14.5% to
17.3% in 2025.\457\ All productivity gains together could allow the
increase in the production of ethanol from 6,000 liters/ha (at 85
liters/ton sugarcane in 2005) to 10,400 liters/ha (at 109 liters/ton
sugarcane) by 2025.\458\ Although not reflected here, there could also
be cost and efficiency improvements related to feedstock collection,
storage, and distribution.
---------------------------------------------------------------------------
\455\ Unicamp ``A Expans[amacr]o do Proalcool como Programa de
Desenvolvimento Nacional''. Powerpoint presentation at Ethanol
Seminar in BNDES, 2006. As sited in OECD, ``Biofuels: Linking
Support to Performance,'' ITF Round Tables No. 138, March 2008.
\456\ Ibid.
\457\ Ibid.
\458\ Ibid.
---------------------------------------------------------------------------
Assuming that ethanol productivity increases to 100 liters/ton by
2015 and 109 liters/ton by 2025, sugarcane costs are be expected to
decrease to approximately $0.51/gal from $0.64/gal since less feedstock
is needed to produce the same volume of ethanol
[[Page 25079]]
using the estimates from Table VIII.A.1-4, above. We assumed a linear
decrease between data points for 2005, 2015, and 2025. Adding operating
($0.26/gal) and capital costs ($0.49/gal) from Table VIII.A.1-4, to a
sugarcane cost of $0.51/gal, total production costs are $1.26/gal in
2022.
Brazil sugarcane producers are also expected to move from burned
cane manual harvesting to mechanical harvesting. As a result, large
amounts of straw are expected to be available. Costs of mechanical
harvesting are lower compared to manually harvesting, therefore, we
would expect costs for sugarcane to decline as greater sugarcane
producers move to mechanical harvesting. However, it is important to
note that diesel use increases with mechanical harvesting, and with
diesel fuel prices expected to increase in the future, costs may be
higher than expected. Therefore, we have not assumed any changes to
harvesting costs due to the switchover from manual harvesting to
mechanical harvesting.
As more straw is expected to be collected at future sugarcane
ethanol facilities, there is greater potential for production of excess
electricity. The production costs estimates in the OECD study assumes
an excess of 40kWh per ton sugarcane, however, future sugarcane plants
are expected to produce 135 kWh per ton sugarcane.\459\ Assuming excess
electricity is sold for $57 per MWh, the production of 95 kWh per ton
would be equivalent to a credit of $0.22 per gallon ethanol produced.
We did not include this potential additional credit from greater use of
bagasse and straw in our estimates at this time. Our cost estimates do
include, however, the excess electricity produced from bagasse that is
currently used today (40 kWh/ton). We are asking for comment on whether
such a credit should be included in our production cost estimates.
---------------------------------------------------------------------------
\459\ Macedo. I.C., ``Green house gases emissions in the
production and use of ethanol from sugarcane in Brazil: The 2005/
2006 Averages and a Prediction for 2020,'' Biomass and Bioenergy,
2008.
---------------------------------------------------------------------------
It is also important to note that ethanol production costs can
increase if the costs of compliance with various sustainability
criteria are taken into account. For instance, using organic or green
cane production, adopting higher wages, etc. could increase production
costs for sugarcane ethanol.\460\ Such sustainability criteria could
also be applicable to other feedstocks, for example, those used in
corn- or soy-based biofuel production. If these measures are adopted in
the future, production costs will be higher than we have projected.
---------------------------------------------------------------------------
\460\ Smeets E, Junginger M, Faaij A, Walter A, Dolzan P,
Turkenburg W, ``The sustainability of Brazilian ethanol--An
Assessment of the possibilities of certified production,'' Biomass
and Bioenergy, 2008.
---------------------------------------------------------------------------
In addition to production costs, there are also logistical and port
costs. We used the report from AgraFNP to estimate such costs since it
was the only resource that included both logistical and port costs. The
total average logistical and port cost for sugarcane ethanol is $0.19/
gal and $0.09/gal, respectively, as shown in Table VIII.A.1-5.
Table VIII.A.1-5--Imported Ethanol Cost at Port in Brazil (2006 $)
------------------------------------------------------------------------
Logistical
Region costs U.S. ($/ Port cost U.S.
gal) ($/gal)
------------------------------------------------------------------------
NE Sao Paulo............................ 0.146 0.094
W Sao Paulo............................. 0.204 0.094
SE Sao Paulo............................ 0.100 0.094
S Sao Paulo............................. 0.170 0.094
N Parana................................ 0.232 0.094
S Goias................................. 0.328 0.094
E Mato Grosso do sul.................... 0.322 0.094
Triangulo mineiro....................... 0.201 0.094
NE Cost................................. 0.026 0.058
Sao Francisco Valley.................... 0.188 0.058
-------------------------------
Average............................. 0.192 0.087
------------------------------------------------------------------------
Total fuel costs must also include the cost to ship ethanol from
Brazil to the U.S. In 2006, this cost was estimated to be approximately
$0.15 per gallon of ethanol.\461\ Costs were estimated as the
difference between the unit value cost of insurance and freight (CIF)
and the unit value customs price. The average cost to ship ethanol from
Caribbean countries (e.g., El Salvador, Jamaica, etc.) to the U.S. in
2006 was approximately $0.12 per gallon of ethanol. Although this may
seem to be an advantage for Caribbean countries, it should be noted
that there would be some additional cost for shipping ethanol from
Brazil to the Caribbean country. Therefore, we assume all costs for
shipping ethanol to be $0.15 per gallon regardless of the country
importing ethanol to the U.S.
---------------------------------------------------------------------------
\461\ Official Statistics of the U.S. Department of Commerce,
USITC.
---------------------------------------------------------------------------
Total imported ethanol fuel costs (at U.S. ports) prior to tariff
and tax for 2022 is shown in Table VIII.A.1-6, at $1.69/gallon. Direct
Brazilian imports are also subject to an additional $0.54 per gallon
tariff, whereas those imports arriving in the U.S. from Caribbean Basin
Initiative (CBI) countries are exempt from the tariff. In addition, all
imports are given an ad valorem tax of 2.5% for undenatured ethanol and
a 1.9% tax for denatured ethanol. We assumed an ad valorem tax of 2.5%
for all ethanol. Thus, including tariffs and ad valorem taxes, the
average cost of imported ethanol is shown in Table VIII.A.1-7 in the
``Brazil Direct w/Tax & Tariff'' and ``CBI w/Tax'' columns for 2022.
[[Page 25080]]
Table VIII.A.1-6--Average Imported Ethanol Costs Prior to Tariff and Taxes in 2022
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transport cost
Sugarcane production cost ($/gal) Operating cost Capital cost Logistical Port cost ($/ from port to Total cost ($/
($/gal) ($/gal) cost ($/gal) gal) U.S. ($/gal) gal)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0.51.................................................... 0.26 0.49 0.19 0.09 0.15 1.69
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VIII.A.1-7--Average Imported Ethanol Costs in 2022
--------------------------------------------------------------------------------------------------------------------------------------------------------
Brazil direct w/tax & tariff
Brazil direct ($/gal) ($/gal) CBI ($/gal) CBI w/tax ($/gal)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1.69.......................................................... 2.27 1.69 1.73
--------------------------------------------------------------------------------------------------------------------------------------------------------
2. Biodiesel and Renewable Diesel Production Costs
Biodiesel and renewable diesel production costs are primarily a
function of the feedstock cost, and to a much lesser extent, the
capital and other operating costs of the facility.
a. Biodiesel
Biodiesel production costs for this rule were estimated using two
versions of a biodiesel production facility model obtained from USDA,
one using degummed soy oil as a feedstock and the other using yellow
grease. The biodiesel from yellow grease model includes the acid pre-
treatment steps required to utilize feedstocks with high free fatty
acid content.
This production model simulates a 10 million gallon per year plant
operating a continuous flow transesterification process. USDA used the
SuperPro Designer chemical process simulation software to estimate heat
and material flowrates and equipment sizing. Outputs from this software
were then combined in a spreadsheet with equipment, energy, labor, and
chemical costs to generate a final estimate of production cost. The
model is described in a 2006 publication in Bioresource Technology,
peer-reviewed scientific journal.\462\ Table VIII.A.2-1 shows the
production cost allocation for the soy oil-to-biodiesel facility as
modeled in the 2022 policy case.
---------------------------------------------------------------------------
\462\ Haas, M.J., A process model to estimate biodiesel
production costs, Bioresource Technology 97 (2006) 671-678.
Table VIII.A.2-1--Production Cost Allocation for Soy Biodiesel Derived
From This Analysis
------------------------------------------------------------------------
Contribution to cost
Cost category (percent)
------------------------------------------------------------------------
Soy Oil................................... 87
Other Materials \a\....................... 5
Capital & Facility........................ 4
Labor..................................... 3
Utilities................................. 1
------------------------------------------------------------------------
\a\ Includes acids, bases, methanol, catalyst.
Soy oil costs were generated by the FASOM agricultural model
(described in more detail in Section IX.A). Historically, the majority
of biodiesel production in the U.S. has used soy oil, a relatively
high-value feedstock, but a growing fraction of biodiesel is being made
from yellow grease, the name given to reclaimed or highly-processed oil
(including corn oil extracted from distillers' grains) that is not
suitable for use in food products. This material typically sells for
about 70% of the value of virgin soy oil. Conversion of yellow grease
into biodiesel requires an additional acid pretreatment step, and
therefore the processing costs are higher than for virgin soy oil
(about $0.40/gal at equal feedstock costs). Table VIII.A.2-2 shows the
feedstock and biodiesel costs used in our cost analysis.
Table VIII.A.2-2--Biodiesel Feedstock and Production Costs Used in This
Analysis (2006$)
------------------------------------------------------------------------
Yellow grease
Soy oil \a\
------------------------------------------------------------------------
Reference Case.......................... .............. ..............
Feedstock $/lb...................... $0.23 $0.16
Bio- diesel $/gal................... $2.11 $1.99
Policy Case............................. .............. ..............
Feedstock $/lb...................... $0.32 $0.22
Bio- diesel $/gal................... $2.75 $2.47
------------------------------------------------------------------------
\a\ Includes corn oil extracted from thin stillage/DGS, rendered fats,
recycled greases, etc.
A co-product of transesterification is crude glycerin. With the
upswing in worldwide biodiesel production in recent years, its market
price is relatively low: In our modeling we assume its value to be
$0.03/lb. As a result, the sale of this material as a co-product only
reduces biodiesel production cost by about $0.02/gal.
b. Renewable Diesel
Renewable diesel is produced in one of three general
configurations: (1) A new standalone unit located within a refinery,
(2) co-processing in an existing refinery diesel hydrotreater, or (3) a
standalone unit at a rendering plant or another location outside of a
refinery. We expect that the largest fraction of the capacity for
refinery installation will be produced using the co-processing method,
as the production costs are lower than those for a new standalone unit
in a refinery. Thus, we speculate that about 50% of renewable diesel
being produced by the refinery co-processing route, 17% from a new
stand alone unit at a refinery and 33% at rendering plants or as a new
site installation. Recent business partnership and construction
announcements related to renewable diesel production (such as involving
ConocoPhillips facilities in Texas, and
[[Page 25081]]
Tyson-Syntroleum facilities in Louisiana) generally support such a
split.
We derived our production cost estimates from documents made
available publicly by UOP, Inc., to make renewable diesel in a grass
roots standalone production process inside a refinery.\463\ The process
has a pre-treating unit that removes alkali and acidic producing
compounds from feed streams, which removes the catalyst poisons. We
also used the UOP engineering estimate to derive costs for co-
processing renewable diesel in an existing refinery's diesel
hydrotreater. For this, we assumed that refiners will: (1) revamp their
existing diesel hydrotreater to add capacity and (2) add a pre-treater
to remove feedstock contaminants. Lastly, we derived costs for a
standalone unit at a location outside a refinery at a rendering plant
other facility, using a capital cost estimate from Syntroleum
Corp.\464\
---------------------------------------------------------------------------
\463\ A New Development in Renewable Fuels: Green Diesel, AM-07-
10 Annual Meeting NPRA, March 18-20, 2007.
\464\ From Securities and Exchange Commission Form 8-K for
Syntroleum Corp, June 25th 07.
---------------------------------------------------------------------------
The extent of the depolymerization and hydrotreating reactions
depend on the process conditions, as some of the carbon backbone of the
oils can be cracked to naphtha and lighter products with higher
severity. For our analysis, we assume no such cracking and predict
yields resulting in ninety-nine percent diesel fuel with the balance as
propane (which could also be considered renewable fuel) and water. We
assume that all of the renewable diesel production will take place in
PADD 2, as feedstock shipping costs are reduced since most of the
sources for feedstock supply are located primarily in the Midwest.
Average processing cost per gallon (in addition to the feedstock) is 41
cents for making renewable diesel from yellow grease/animal fats, based
on our cost methodology.
As with biodiesel, renewable diesel cost estimates were based on
soy oil feedstock prices taken from the FASOM modeling work, given in
Section IX.A. Our cost estimates for renewable diesel were focused on
use of yellow grease as a feedstock, given the project announcements
mentioned above, as well as the relative insensitivity of the
hydrotreating process to fatty acids and other contaminates relative to
the transesterification process. Oil from corn fractionation, yellow
grease, and animal fat prices were assumed to be 70% the price of soy
oil (consistent with historical market trends). For our 2022 policy
case, with a yellow grease price of $0.23/lb, the production cost is
$2.47/gal for biodiesel and $2.10/gal for renewable diesel (2006$).
Table VIII.A.2-3 shows the projected volume contribution to the
biodiesel and renewable diesel total volume, their production costs,
and the weighted average production cost used for biodiesel and
renewable diesel in this proposal. These results assume feedstock
prices are plant-gate and do not include any product transportation
costs. Note also that the volumes here include co-processed renewable
diesel which does not qualify as biomass-based diesel but which may be
counted as advanced biofuel.
Table VIII.A.2-3--Projected Costs and Volume Contribution for Biodiesel
and Renewable Diesel
[Policy case, 2006$ and million gallons]
------------------------------------------------------------------------
Fuel Cost Volume
------------------------------------------------------------------------
Biodiesel from virgin plant oil......... 2.75 660
Biodiesel from oil extraction at ethanol 2.47 150
plants, yellow grease..................
Renewable diesel from fat, oil, yellow 2.10 375
grease.................................
Weighted average cost & total volume.... 2.51 1,185
------------------------------------------------------------------------
Although the per-gallon cost for making renewable diesel from
yellow grease is significantly less than using the biodiesel process,
there are a number of reasons why we believe the latter will still be
used to process some yellow grease (and most of the virgin oil
feedstocks). The primary reason is that there is already sufficient
biodiesel capacity existing or under construction to cover the
projected volumes. Secondly, the per-gallon capital cost to build new
hydroprocessing capacity for renewable diesel is expected to be
significantly higher than for the biodiesel process. The low per-gallon
renewable diesel cost given here is based on the majority of the
production being done by co-processing at existing petroleum
refineries.
3. BTL Diesel Production Costs
Biofuels-to-Liquids (BTL) processes, which are also thermochemical
processes, convert biomass to liquid fuels via a syngas route. The
primary product produced by this process is diesel fuel.
There are many steps involved in a BTL process which makes this a
capital-intensive process. The first step, like all the cellulosic
processes, requires that the feedstocks be processed to be dried and
ground to a fine size. The second step is the syngas step, which
thermochemically reacts the biomass to carbon monoxide and hydrogen.
Since carbon monoxide production exceeds the stoichiometric ideal
fraction of the mixture, a water shift reaction must be carried out to
increase the relative balance of hydrogen. The syngas products must
then be cleaned to facilitate the following Fischer-Tropsch reaction.
The Fischer-Tropsch reaction reacts the syngas to a range of
hydrocarbon compounds--a type of synthetic crude oil. This hydrocarbon
mixture is then hydrocracked to maximize the production of high cetane
diesel fuel, although some low octane naphtha is also produced. The
many steps of the BTL process contribute to its high capital cost.
One estimate made by Iowa State University estimates the total cost
for a cellulosic Fischer-Tropsch plant that produces 35 million gallons
per year diesel fuel at $2.37 per gallon. This cost estimated the
capital costs to be $341 million. These costs were estimated in the
year 2002. We adjusted the operating and capital costs to a 2006
investment environment and to 2006 dollars based the costs on our
average $71/dry ton feedstock costs which increases the total cost to
$2.85 per gallon of diesel fuel.
Initially, the estimated cost of $2.85 per gallon seems high
relative to the projected cost for a year 2015 biochemical cellulosic
plant, which is $1.39 per gallon of ethanol in 2006 dollars. However,
ethanol provides about half the energy content as Fischer-Tropsch
diesel fuel. So if we double the biochemical cellulosic ethanol costs
to $2.78 per diesel fuel-equivalent gallon,
[[Page 25082]]
the estimated costs are very consistent between the two. The cellulosic
biofuel tax subsidy favors the biochemical ethanol plant, though,
because it is a per-gallon subsidy regardless of the energy content,
and it therefore offsets twice as much cost as the BTL plant producing
diesel fuel. There is one more issue worth considering and that is the
relative price of diesel fuel to that of E85. Recently diesel fuel has
been priced much higher than gasoline, and if this trend continues to
hold, it would provide a better market for selling the BTL diesel fuel
than for selling biochemical ethanol into the E85 market, which we
believe will be a challenging pricing market for refiners.
4. Catalytic Depolymerization Costs
A new technology was developed by Cello Energy which catalytically
depolymerizes cellulose, and then repolymerizes it to produce synthetic
hydrocarbon fuels such as gasoline, jet fuel and diesel fuel The
company claims that they can produce diesel fuel for about $0.40 per
gallon by processing hay, wood chips and used tires. Based on our
projections of future cellulosic feedstock costs, their production
costs for using only cellulosic feedstocks and assuming the cellulosic
feedstock costs developed above would likely be about $1.00 per gallon.
In late 2008 the company started up a 20 million gallon per year
commercial demonstration plant as a first step towards commercializing
their process. We discuss this technology and its costs in more detail
in the DRIA.
B. Distribution Costs
Our analysis of the costs associated with distributing the volumes
of renewable fuels that we project will be used under RFS2 focuses on:
(1) The capital cost of making the necessary upgrades to the fuel
distribution infrastructure system directly related to handling these
fuels, and (2) the ongoing additional freight costs associated with
shipping renewable fuels to the point where they are blended with
petroleum-based fuels.\465\ The following sections outline our
estimates of the distribution costs for the additional volumes of
ethanol, FAME biodiesel, and renewable diesel fuel that would be used
in response to the RFS2 standards.\466\
---------------------------------------------------------------------------
\465\ The anticipated ways that the renewable fuels projected to
be used in response to the EISA will be distributed is discussed in
Section V.C. of today's preamble.
\466\ Please refer to Section 4.2 of the DRIA for additional
discussion of how these estimates were derived.
---------------------------------------------------------------------------
A discussion of the capability of the transportation system to
accommodate the volumes of renewable fuels projected to be used under
RFS2 is contained in Section V.C. of today's preamble. There will be
ancillary costs associated with upgrading the basic rail, marine, and
road transportation nets to handle the increase in freight volume due
to the RFS2. We have not sought to quantify these ancillary costs
because (1) the growth in freight traffic that is attributable to RFS2
represents a minimal fraction of the total anticipated increase in
freight tonnage (approximately 2% by 2022, see Section V.C.4.), and (2)
we do not believe there is an adequate way to estimate such non-direct
costs. We will continue to evaluate issues associated with the
expansion of the basic transportation net to accommodate the volumes of
renewable fuels projected under RFS2 and will update our analysis for
the final rule based on our findings.
1. Ethanol Distribution Costs
a. Capital Costs To Upgrade the Distribution System for Increased
Ethanol Volume
Table VIII.B.1-1 contains our estimates of the infrastructure
changes and associated capital costs to support the use of the
additional 21 BGY of ethanol that we project will be used under RFS2 by
2022 relative to the AEO 2007 forecast of 13 BGY.\467\ The total
estimated capital costs are estimated at $12.1 billion which when
amortized equates to approximately 6.9 cents per gallon of this
additional ethanol volume.\468\
---------------------------------------------------------------------------
\467\ See Section V.C. of today's preamble for discussion of the
upgrades we project will be needed to the distribution system to
handle the increase in ethanol volumes under EISA.
\468\ These capital costs will be incurred incrementally through
2022 as ethanol volumes increase. Capital costs for tank trucks were
amortized over 10 years with a 7% cost of capital. Other capital
costs were amortized over 15 years with a 7% return on capital.
Table VIII.B.1-1--Estimated Ethanol Distribution Infrastructure Capital
Costs \a\
------------------------------------------------------------------------
Million $
------------------------------------------------------------------------
Fixed Facilities: ...........
Marine Import Facilities................................... 49
Ethanol Receipt Rail Hub Terminals:
Rail Car Handling & Misc. Equipment...................... 1,264
Ethanol Storage Tanks.................................... 354
Petroleum Terminals: ...........
Rail Receipt Facilities.................................. 2,482
Ethanol Storage Tanks.................................... 1,611
Ethanol Blending & Misc. Equipment....................... 545
Retail..................................................... 2,957
Mobile Facilities:
Rail Cars.................................................. 2,938
Barges..................................................... 183
Tank Trucks................................................ 223
------------
Total Capital Costs...................................... 12,066
------------------------------------------------------------------------
\a\ Relative to a 13.18 BGY 2022 reference case.
We request comment on our basis for these estimates as detailed in
chapter 4.2 of the DRIA. Comment is specifically requested on the
extent to which ethanol rail receipt would be accommodated within
petroleum terminals rather than being cited at rail hub terminals (to
be further shipped by tank truck to petroleum terminals). Our current
analysis estimated that half of the new ethanol rail receipt capability
needed to support the use of the projected ethanol volumes under the
EISA would be installed at petroleum terminals, and half would be
installed at rail terminals. A recently completed study by ORNL
estimated that all new ethanol rail receipt capability would be
installed at existing rail terminals given the limited ability to
install such capability at petroleum terminals.\469\
---------------------------------------------------------------------------
\469\ ``Analysis of Fuel Ethanol Transportation Activity and
Potential Distribution Constraints'', prepared for EPA by Oak Ridge
National Laboratory, March 2009.
---------------------------------------------------------------------------
b. Ethanol Freight Costs
We estimate that ethanol freight costs would be 11.3 cents per
gallon on a national average basis. Ethanol freight costs are based on
those we derived for the Renewable Fuel Standard final rule updated to
reflect the projected ethanol use patterns and effect on distribution
patterns of increased imports and more dispersed domestic ethanol
production locations.\470\ Specifically, we estimated freight costs by
assessing the location of production and import volumes, where ethanol
would be used, and the modes and distances for transportation between
production and use.\471\ We intend to update our estimate of ethanol
freight costs for the final rule based on a recently completed analysis
conducted for EPA by Oak Ridge National Laboratory (ORNL). The ORNL
[[Page 25083]]
analysis contains more detailed projections of which transportation
modes and combination of modes (e.g., unit train to barge) are best
suited for delivery of ethanol to specific markets considering ethanol
source and end use locations, the current configuration and projected
evolution of the distribution system, and cost considerations for the
different transportation modes.
---------------------------------------------------------------------------
\470\ Please refer to Section 4.2 of the DRIA for additional
discussion of ethanol freight costs.
\471\ Our projections regarding the location of ethanol
production/import volumes and where ethanol would be used is
discussed in Sections V.B. and V.D. of today's preamble
respectively.
---------------------------------------------------------------------------
2. Biodiesel and Renewable Diesel Distribution Costs
a. Capital Costs To Upgrade the Distribution System for Increased FAME
Biodiesel Volume
Table VIII.B.2-1 contains our estimates of the infrastructure
changes and associated capital costs to support the use of the
additional 430 MGY of FAME biodiesel that we project will be used under
RFS2 by 2022.\472\ The total capital costs are estimated at $381
million which equates to approximately 9.8 cents per gallon of
additional biodiesel volume.\473\
---------------------------------------------------------------------------
\472\ We project that by 2022 380 MGY of FAME biodiesel would be
used absent the requirements under EISA and that a total of 810 MGY
of FAME biodiesel would be used under the EISA.
\473\ These capital costs will be incurred incrementally through
2022 as FAME biodiesel volumes increase. Capital costs for tank
trucks were amortized over 10 years with a 7% cost of capital. Other
capital costs were amortized over 15 years with a 7% return on
capital.
Table VIII.B.2-1--Estimated FAME Biodiesel Distribution Infrastructure
Capital Costs \a\
------------------------------------------------------------------------
Million $
------------------------------------------------------------------------
Fixed Facilities:
Petroleum Terminals:
Storage Tanks............................................ 129
Biodiesel Blending & Misc. Equipment..................... 192
Mobile Facilities:
Rail Cars.................................................. 35
Barges..................................................... 17
Tank Trucks................................................ 8
------------
Total Capital Costs...................................... 381
------------------------------------------------------------------------
\a\ Relative to a 380 MGY 2022 reference case.
b. Biodiesel Freight Costs
We estimate that biodiesel freight costs would be 9.3 cents per
gallons on a national average basis. Priority regional demand for
biodiesel was estimated by reviewing State biodiesel mandates/
incentives and assuming a demand for 2% biodiesel in most heating oil
used in the Northeast by 2022. This priority regional demand was
assumed to be filled first from local plants that could ship
economically by tank truck. The remaining fraction of priority regional
demand was assumed to be satisfied from more distant plants via
shipment by manifest rail car. Overall shipping distances were
minimized in selecting which plants would satisfy the demand for a
given area. The amount of biodiesel that we project would be consumed
which would not be directed to priority demand was assumed to be used
within trucking distance of the production plant to the extent possible
while maintaining biodiesel blend concentrations below 5%. The
remaining volume needed to match our estimated production volume was
assumed to be shipped via manifest rail car to the nearest areas where
diesel fuel use was not already saturated with biodiesel to the 5%
level.
c. Renewable Diesel Distribution System Capital and Freight Costs
We project that there would be no additional costs associated with
distributing the 250 MGY of renewable diesel fuel that we estimate will
be produced at refineries by 2022.\474\ This renewable diesel fuel will
be blended into finished diesel fuel at the refinery and be distributed
to petroleum terminals in the same way 100% petroleum-based distillate
fuel is distributed. This is based on our belief that renewable diesel
will be confirmed to be sufficiently similar to petroleum-based diesel
with respect to distribution system compatibility.
---------------------------------------------------------------------------
\474\ This includes co-processed renewable diesel fuel as well
as renewable diesel fuel produced in separate processing units
located at refineries.
---------------------------------------------------------------------------
We project that 125 MGY of renewable diesel will be produced at
stand-alone facilities that are not connected to a refinery or
petroleum terminal. We estimate that such renewable diesel will be
trucked to nearby petroleum terminals at a cost of 5 cents per gallon.
We estimate that 8 additional tank trucks would be needed to carry this
renewable diesel to terminals at a total cost of approximately $1.3
million dollars. Amortized over 10 years with a 7% cost of capital, the
total capital costs equate to approximately 0.2 cents per gallon of
renewable diesel fuel produced at stand-alone facilities. We estimate
that no further capital costs would need to be incurred to handle
renewable diesel fuel. This is based on the assumption that renewable
diesel delivered to terminals from stand-alone production facilities
can be mixed directly into storage tanks that contain petroleum-based
diesel fuel or can be stored separately in existing storage tanks for
later blending with petroleum-based diesel fuel. We further estimate
the terminals that receive renewable diesel will not need to install
additional facilities to allow the receipt by tank truck.
C. Reduced Refining Industry Costs
As renewable and alternative fuel use increases, the volume of
petroleum-based products, such as gasoline and diesel fuel, would
decrease. This reduction in finished refinery petroleum products is
associated with reduced refinery industry costs. The reduced costs
would essentially be the volume of fuel displaced multiplied by the
cost for producing the fuel. There is also a reduction in capital costs
which is important because by not investing in new refinery capital,
more resources are freed up to build plants that produce renewable and
alternative fuels.
Although we conducted refinery modeling for estimating the cost of
blending ethanol, we did not rely on the refinery model results for
estimating the volume of displaced petroleum. Instead we conducted an
energy balance around the increased use of renewable fuels, estimating
the energy-equivalent volume of gasoline or diesel fuel displaced. This
allowed us to more easily apply our best estimates for how much of the
petroleum would displace imports of finished products versus crude oil
for our energy security analysis which is discussed in Section IX.B of
this preamble.
As part of this analysis we accounted for the change in petroleum
demanded by upstream processes related to additional production of the
renewable fuels as well as reduced production of petroleum fuels. For
example, growing corn used for ethanol production requires the use of
diesel fuel in tractors, which reduces the volume of petroleum
displaced by the ethanol. Similarly, the refining of crude oil uses by-
product hydrocarbons for heating within the refinery, therefore the
overall effect of reduced gasoline and diesel fuel consumption is
actually greater because of the additional upstream effect. We used the
lifecycle petroleum demand estimates provided for in GREET model to
account for the upstream consumption of petroleum for each of the
renewable and alternative fuels, as well as for gasoline and diesel
fuel. Although there may be some renewable fuel used for upstream
energy, we assumed that this entire volume is petroleum because the
volume of renewable and alternative fuels is fixed as described in
Section V above.
For this proposed rule, we assumed that a portion of the gasoline
displaced
[[Page 25084]]
by ethanol is imported, while the other portion is produced from
domestic refineries. The assumption we made is that one half of the
ethanol market in the Northeast, which comprises about half of the
nation's gasoline demand, would displace imported gasoline or gasoline
blend stocks. Therefore, to derive the portion of the new renewable
fuels which would offset imports (and not impact domestic refinery
production), we multiplied the total volume of petroleum fuel displaced
by 50% to represent that portion of the ethanol which would be used in
the Northeast, and 50% again to only account for that which would
offset imports. The rest of the ethanol, including half of the ethanol
presumed to be used in the Northeast, is presumed to offset domestic
gasoline production. In the case of biodiesel and renewable diesel, all
of it is presumed to offset domestic diesel fuel production. For
ethanol, biodiesel and renewable diesel, the amount of petroleum fuel
displaced is estimated based on the relative energy contents of the
renewable fuels to the fuels which they are displacing. The savings due
to lower imported gasoline and diesel fuel is accounted for in the
energy security analysis contained in Section IX.B.
For estimating the U.S. refinery industry cost reductions, we
multiplied the estimated volume of domestic gasoline and diesel fuel
displaced by the wholesale price for each of these fuels, which are
$157 per gallon for gasoline, and $161 per gallon for diesel fuel at
$53/bbl crude oil, and $267 per gallon for gasoline, and $335 per
gallon for diesel fuel at $92/bbl crude oil. For the volume of
petroleum displaced upstream, we valued it using the wholesale diesel
fuel price. Table VIII.C.1-1 shows the net volumetric impact on the
petroleum portion of gasoline and diesel fuel demand, as well as the
reduced refining industry costs for 2022.
Table VIII.C.1-1--Reduced U.S. Refinery Industry Costs for the RFS2 Program in 2022
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Total volume Cost savings at Cost savings at
displaced $53/bbl crude oil $92/bbl crude oil
(billion gallons) price price
(billion dollars) (billion dollars)
----------------------------------------------------------------------------------------------------------------
Upstream......................... Petroleum........... 0.8 -$1.3 -$2.7
End Use.......................... Gasoline............ 10.4 16.3 27.7
Diesel Fuel......... 0.6 0.9 1.9
--------------------------------------------------------
Total............ ................. 15.9 26.9
----------------------------------------------------------------------------------------------------------------
D. Total Estimated Cost Impacts
The previous sections of this chapter presented estimates of the
cost of producing and distributing corn-based and cellulosic-based
ethanol, imported ethanol, biodiesel, and renewable diesel. In this
section, we briefly summarize the methodology used and the results of
our analysis to estimate the cost and other implications for increased
use of renewable fuels to displace gasoline and diesel fuel. An
important aspect of this analysis is refinery modeling which primarily
was used to estimate the costs of blending ethanol into gasoline, as
well as the overall refinery industry impacts of the proposed fuel
program. The refinery modeling was conducted by Jacobs Consultancy
under subcontract to Southwest Research Institute. A detailed
discussion of how the renewable fuel volumes affect refinery gasoline
production volumes and cost is contained in Chapter 4 of the DRIA.
1. Refinery Modeling Methodology
The refinery modeling was conducted in three distinct steps. The
first step involved the establishment of a 2004 base case which
calibrated the refinery model against 2004 volumes, gasoline quality,
and refinery capital in place. The EPA and ASTM fuel quality
constraints in effect by 2004 are imposed on the products.
For the second step, we established a 2022 future year reference
case which represents a business-as-usual case as estimated by the
2007Annual Energy Outlook (AEO). The refinery model assumed that the
price of crude oil would average about $51 per barrel, though the
results were later adjusted to reflect $53 and $92 per barrel crude oil
prices. We also modeled the implementation of several new environmental
programs that will have required changes in fuel quality by 2022,
including the 30 part per million (ppm) average gasoline sulfur
standard, the 15 ppm cap standards on highway and nonroad diesel fuel,
the Mobile Source Air Toxics (MSAT) 0.62 volume percent benzene
standard. We modeled the implementation of EPAct of 2005, which by
rescinding the reformulated gasoline oxygenate standard, resulted in
the discontinued use of MTBE, and a large increase in the amount of
ethanol blended into reformulated gasoline. We also modeled the EISA
Energy Bill corporate average fuel economy (caf[eacute]) standards in
the reference case because it will be phasing-in, and affect the phase-
in of the RFS2. We modeled 13.2 billion gallons of ethanol in the
gasoline pool and 0.4 billion gallons of biodiesel in the diesel pool
for 2022, which is the ``business-as-usual'' volume as projected by AEO
2007.
The third step, or the control case, involved the modeling of the
34 billion gallons of ethanol and 1 billion gallons of biodiesel and
renewable diesel in 2022 to comply with EISA when the proposed
renewable fuels program is fully phased-in. All the other environmental
and ASTM fuel quality constraints are assumed to apply to the control
case as well to solely model the impact of the RFS2 standards.
The price of ethanol and E85 used in the refinery modeling is a
critical determinant of the overall economics of using ethanol. Ethanol
was priced initially based on the historical average price spread
between regular grade conventional gasoline and ethanol, but then
adjusted post-modeling to reflect the projected production cost for
both corn and cellulosic-based ethanol. The refinery modeling assumed
that all ethanol added to gasoline for E10 is match-blended for octane
by refiners in the reference and control cases, although splash
blending of ethanol was assumed to be appropriate for the conventional
gasoline for the base case based on EPA gasoline data. For the control
case, E85 was assumed to be priced much lower than gasoline to reflect
its lower energy content, longer refueling time and lower availability
(see Chapter 4 of the DRIA for a detailed discussion for how we
projected E85 prices). E85 is assumed to be blended
[[Page 25085]]
with gasoline blendstock designed for blending with E10, and a small
amount of butane to bring the RVP of E85 up to that of gasoline. Thus,
unlike current practices today where E85 is blended at 85% in the
summer and E70 in the winter, we assumed that E85 is blended at 85%
year-round. E85 use in any one market is limited to levels which we
estimated would reflect the ability of FFV vehicles in the area to
consume the E85 volume.
The refinery model was provided some flexibility and also was
constrained with respect to the applicable gasoline volatility
standards for blending up E10. The refinery model allowed conventional
gasoline and most low RVP control programs to increase by 1.0 pounds
per square inch (psi) in Reid Vapor Pressure (RVP) waiver during the
summer. However, wintertime conventional gasoline was assumed to comply
with the wintertime ASTM RVP and Volume/Liquid (V/L) standards.
The costs for producing, distributing and using biodiesel and
renewable diesel are accounted for outside the refinery modeling. Their
production and distribution costs are estimated first, compared to the
costs of producing diesel fuel, and then are added to the costs
estimated by the refinery cost model for blending the ethanol.
The costs were adjusted to reflect the crude oil prices estimated
by EIA in its Annual Energy Outlook (AEO). The AEO 2008 reference case
projects that crude oil will be $53 per barrel in 2022, so we adjusted
our costs slightly to reflect that slightly higher crude oil price. We
also evaluated a higher crude oil price case. The high crude oil case
price modeled for the AEO projects that crude oil will be $92 per
barrel in 2022, so we adjusted our cost model to also estimate the
program costs based on this higher crude oil cost. We estimated the
program costs based on these different crude oil prices by adjusting
the gasoline and diesel fuel prices to reflect the cost of crude oil.
The crude oil costs also have a secondary impact on the production
costs of various renewable and alternative fuels (e.g., petroleum used
to grow corn which also has been reflected in our cost analysis).
2. Overall Impact on Fuel Cost
Based on the refinery modeling conducted for today's proposed rule,
we calculated the costs for consuming the additional 22 billion gallons
of renewable fuels in 2022 relative to the reference case. The costs
are reported separately for blending ethanol into gasoline as E10 and
E85, and for blending biodiesel and renewable diesel with diesel fuel.
The costs are expressed two different ways. First, we express the full
``engineering'' cost of the program without the ethanol consumption tax
subsidies in which the costs are based on the total accumulated costs
of each of the fuels changes, at both reference case and high crude oil
prices. Second, we express the costs subtracting the ethanol and
biodiesel and renewable diesel consumption tax subsidies since some or
perhaps most of the cost of the tax subsidy may not be reflected in the
price consumers pay at retail. In all cases, the capital costs are
amortized at seven percent return on investment (ROI) before taxes, and
based on 2006 dollars.
a. Costs Without Federal Tax Subsidies
Table VIII.D.2-1 summarizes the costs without ethanol tax subsidies
for each of the two 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.\475\ This estimate of costs reflects the
changes in gasoline that are occurring with the expanded use of
renewable and alternative fuels. These costs include the labor, utility
and other operating costs, fixed costs and the capital costs for all
the fuel changes expected. The per-gallon costs are derived by dividing
the total costs over all U.S. gasoline and diesel fuel projected to be
consumed in 2022. Note that these costs are incremental only to the
reference case volumes of renewable fuels (costing out about 20 billion
gallons of new renewable fuels) and does not reflect the costs of the
renewable fuel volumes in the reference case.
---------------------------------------------------------------------------
\475\ 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 VIII.D.2-1--Estimated Costs of the RFS2 Program in 2022
[2006 dollars, 7% ROI before taxes]
----------------------------------------------------------------------------------------------------------------
$53 per barrel of $92 per barrel of
crude oil incremental crude oil incremental
to reference case to reference case
----------------------------------------------------------------------------------------------------------------
Gasoline Impacts....................... $billion/yr.............. 17.0 4.1
c/gal.................... 10.91 2.65
Diesel Fuel Impacts.................... $billion/yr.............. 0.78 -0.05
c/gal.................... 1.20 -0.07
---------------------------------------------
Total Impact....................... $billion/yr.............. 17.8 4.1
----------------------------------------------------------------------------------------------------------------
Our analysis shows, as expected, that the RFS2 program is more cost
effective at the higher assumed price of crude oil. At our assumed
crude oil price of $53 per barrel, the gasoline and diesel fuel costs
are projected to increase by $17.0 billion and $0.78 billion,
respectively, or $17.8 billion in total. Expressed as per-gallon costs,
these fuel changes would increase the cost of producing gasoline and
diesel fuel by 10.91 and 1.20 cents per gallon, respectively. At the
assumed crude oil price of $92 per barrel, the gasoline costs are
projected to increase by $4.1 billion and the diesel fuel costs are
projected to decrease by $0.05 billion, or increase by $4.1 billion in
total. Expressed as per-gallon costs, these fuel changes would increase
gasoline costs by 2.65 and decrease diesel fuel costs by 0.07 cents per
gallon at the higher crude oil price. Our analysis shows that at the
higher crude oil price, ethanol, biodiesel and renewable diesel fuel
use would be much less costly to use.
The increased use of renewable and alternative fuels would require
capital investments in corn and cellulosic ethanol plants, and
renewable diesel fuel plants. In addition to producing the fuels,
storage and distribution facilities along the whole distribution chain,
including at retail, will have to be constructed for these new fuels.
Conversely, as these renewable and
[[Page 25086]]
alternative fuels are being produced, they supplant gasoline and diesel
fuel demand which results in less new investments in refineries
compared to business as usual. In Table VIII.D.2-2, we list the total
incremental capital investments that we project would be made for this
proposed RFS2 rulemaking incremental to the AEO 2007 reference case.
Table VIII.D.2-2--Total Projected U.S. Capital Investments for the RFS2
Program
[billion dollars]
------------------------------------------------------------------------
Capital
Plant Type Costs
------------------------------------------------------------------------
Corn Ethanol.............................................. 4.0
Cellulosic Ethanol........................................ 50.1
Ethanol Distribution...................................... 12.4
Bio/Renew Diesel Fuel Production and Distribution......... 0.25
Refining.................................................. -7.9
-------------
Total................................................... 58.9
------------------------------------------------------------------------
Table VIII.D.2-2 shows that the total U.S. incremental capital
investments attributed to this program for 2022 are $58.9 billion. One
contributing reason why the capital investments made for renewable
fuels technologies is so much more than the decrease in refining
industry capital investments is that a large part of the decrease in
petroleum gasoline supply was from reduced imports. In addition,
renewable fuels technologies are more capital intensive per gallon of
fuel produced than incremental increases in gasoline and diesel fuel
production at refineries.
b. Gasoline and Diesel Costs Reflecting the Tax Subsidies
Table VIII.D.2-3 below expresses the total and per-gallon gasoline
costs for the two control scenarios showing the effect of the Federal
tax subsidies. The Federal tax subsidy is 45 cents per gallon for each
gallon of new corn ethanol blended into gasoline and $1.01 per gallon
for each gallon of cellulosic ethanol. Imported ethanol also receives
the 45 cents per gallon Federal tax subsidy, although the portion of
imported ethanol which exceeds the volume of imported ethanol exempted
through the Caribbean Basin Initiative (CBI) would have to pay a 51
cents per gallon tariff. We estimate that in 2022 imported ethanol
would receive a net 23 cents per gallon subsidy after we account for
both the subsidy and projected volume of imported ethanol subjected to
the tariff. While there are also state ethanol tax subsidies we did not
consider those subsidies. A $1 per gallon subsidy currently applies to
biodiesel produced from virgin plant oils (i.e., soy) and a 50 cent per
gallon subsidy applies to biodiesel and renewable diesel fuel produced
from waste fats and oils; we assume that these subsidies continue.\476\
The subsidies, if passed along to the consumer, reduce the apparent
cost of the program to the consumer at retail since part of the program
cost is being paid through taxes. The cost reduction attributed to the
subsidies is estimated by multiplying the value of the subsidies times
the volume of new corn and cellulosic ethanol used in transportation
fuels.
---------------------------------------------------------------------------
\476\ The recent economic bailout law increased the subsidy
provided to renewable diesel fuel to $1 per gallon, but we were not
able incorporate this change in time for this proposed rulemaking.
Table VIII.D.2-3--Estimated Costs of the RFS2 Program in 2022
[Reflecting Tax Subsidies, 2006 dollars, 7% ROI before taxes]
----------------------------------------------------------------------------------------------------------------
$53 per barrel of $93 per barrel of
crude oil incremental crude oil incremental
to reference case to reference case
----------------------------------------------------------------------------------------------------------------
Gasoline Impacts....................... $billion/yr.............. -0.74 -13.6
c/gal.................... -0.48 -8.74
Diesel Fuel Impacts.................... $billion/yr.............. 0.25 -0.57
c/gal.................... 0.39 -0.88
---------------------------------------------
Total Impact....................... $billion/yr.............. -0.49 -14.2
----------------------------------------------------------------------------------------------------------------
Our analysis shows, as expected, that the overall costs of the RFS2
program appears to be lower when considering the ethanol consumption
subsidies. At the assumed crude oil price of $53 per barrel, the
gasoline and diesel fuel costs are projected to decrease by $0.74
billion and increase $0.25 billion, respectively, or $-0.49 billion in
total. Expressed as per-gallon costs, these fuel changes would decrease
gasoline costs by -0.48 cents per gallon and increase diesel fuel costs
by 0.39 cents per gallon. At the assumed crude oil price of $92 per
barrel, the gasoline and diesel fuel costs are projected to decrease by
$13.6 billion and $0.57 billion, respectively, or $14.2 billion in
total. Expressed as per-gallon costs, these fuel changes would decrease
gasoline and diesel fuel by 8.74 and 0.88 cents per gallon,
respectively. Reducing the cost by the tax subsidies, which more
closely represents the prices paid by consumers at the pump, our
analysis shows that at lower crude oil prices that the cost of the
program would be very small. However, at the higher oil prices and
including the subsidies, the program's costs are very negative.
IX. Economic Impacts and Benefits of the Proposal
A. Agricultural Impacts
EPA used two principal tools to model the potential domestic and
international impacts of the RFS2 on the U.S. and global agricultural
sectors. The Forest and Agricultural Sector Optimization Model (FASOM),
developed by Professor Bruce McCarl of Texas A&M University and others,
provides detailed information on domestic agricultural and greenhouse
gas impacts of renewable fuels. The Food and Agricultural Policy
Research Institute (FAPRI) at Iowa State University and the University
of Missouri-Columbia maintains a number of econometric models that are
capable of providing detailed information on impacts on international
agricultural markets from the wider use of renewable fuels in the U.S.
FASOM is a long-term economic model of the U.S. agriculture sector
that attempts to maximize total revenues for producers while meeting
the demands of consumers. FASOM can be utilized to estimate which
crops, livestock, and processed agricultural products would be produced
in the U.S. given RFS2 biofuel requirements. In each model simulation,
crops compete for price sensitive inputs such as land and labor at the
regional level and the cost of
[[Page 25087]]
these and other inputs are used to determine the price and level of
production of primary commodities (e.g., field crops, livestock, and
biofuel products). FASOM also estimates prices using costs associated
with the processing of primary commodities into secondary products
(e.g., converting livestock to meat and dairy, crushing soybeans to
soybean meal and oil, etc.). FASOM does not capture short-term
fluctuations (i.e., month-to-month, annual) in prices and production,
however, as it is designed to identify long-term trends (i.e., five to
ten years). The domestic results provided throughout this analysis
incorporate the agricultural sector component of the FASOM model.
The FASOM model also contains a forestry component. Running both
the forestry and agriculture components of the model would show the
interaction between these two sectors. However, the analysis for this
proposal only shows the results from the agriculture component with no
interaction from the forestry sector, as the forestry component of the
model is in the process of being updated. We plan to utilize a complete
version of the model for our analysis in the final rule, where
agricultural land use impacts also affect forestry land use, and
cellulosic ethanol produced from the forestry sector will affect
cellulosic ethanol production in the agriculture sector.
The FAPRI models are econometric models covering many agricultural
commodities. These models capture the biological, technical, and
economic relationships among key variables within a particular
commodity and across commodities. They are based on historical data
analysis, current academic research, and a reliance on accepted
economic, agronomic, and biological relationships in agricultural
production and markets. The international modeling system includes
international grains, oilseeds, ethanol, sugar, and livestock models.
In general, for each commodity sector, the economic relationship that
supply equals demand is maintained by determining a market-clearing
price for the commodity. In countries where domestic prices are not
solved endogenously, these prices are modeled as a function of the
world price using a price transmission equation. Since econometric
models for each sector can be linked, changes in one commodity sector
will impact other sectors. Elasticity values for supply and demand
responses are based on econometric analysis and on consensus estimates.
Additional information on the FASOM and FAPRI models is included in the
Draft Regulatory Impact Analysis (DRIA Chapter 5).
For the agricultural sector analysis using the FASOM and FAPRI
models of the RFS2 biofuel volumes, we assumed 15 billion gallons
(Bgal) of corn ethanol would be produced for use as transportation fuel
by 2022, an increase of 2.7 Bgal from the Reference Case. Also, we
modeled 1.0 Bgal of biodiesel used as fuel in 2022, an increase of 0.6
Bgal from the Reference Case. In addition, we modeled an increase of 10
Bgal of cellulosic ethanol in 2022. In FASOM, this volume consists of
7.5 billion gallons of cellulosic ethanol coming from corn residue in
2022, 1.3 billion gallons from switchgrass and 1.4 billion gallons from
sugarcane bagasse. Though these volumes differ slightly from those
analyzed in Section V.B.2.c.iv, we will work to align the volumes for
the final rulemaking.
Given the short timeframe for conducting this analysis, some of the
projected sources of biofuels analyzed in the RFS2 proposal are not
currently modeled in FASOM and FAPRI. For example, biodiesel from corn
oil fractionation is not currently accounted for in FASOM. In addition,
since FASOM is a domestic agricultural sector model, it can't be
utilized to examine the impacts of the wider use of biofuel imports
into the U.S. Also, neither of the two models used for this analysis--
FASOM or FAPRI--include biofuels derived from domestic municipal solid
waste or from the U.S. forestry sector. Thus, for the RFS2 agricultural
sector analysis, these biofuel sources are analyzed outside of the
agricultural sector models.
All the results presented in this section are relative to the AEO
2007 Reference Case renewable fuel volumes, which include 12.3 Bgal of
grain-based ethanol, 0.4 Bgal of biodiesel, and 0.3 Bgal of cellulosic
ethanol in 2022. The domestic figures are provided by FASOM, and all of
the international numbers are provided by FAPRI. The detailed FASOM
results, detailed FAPRI results, and additional sensitivity analyses
are described in more detail in the DRIA. We seek comment on this
analysis of the agricultural sector impacts resulting from the wider
use of renewable fuels.
Table IX.A.1-1--Biofuel Volumes Modeled in 2022
[Billions of Gallons]
----------------------------------------------------------------------------------------------------------------
Biofuel Reference Case Control Case Change
----------------------------------------------------------------------------------------------------------------
Corn Ethanol............................................. 12.3 15.0 2.7
Corn Residue Cellulosic Ethanol.......................... 0 7.5 7.5
Sugarcane Bagasse Cellulosic Ethanol..................... 0.3 1.4 1.1
Switchgrass Cellulosic Ethanol........................... 0 1.3 1.3
Other Ethanol............................................ 0 0.2 0.2
Biodiesel................................................ 0.4 1.0 0.6
----------------------------------------------------------------------------------------------------------------
1. Commodity Price Changes
For the scenario modeled, FASOM predicts that in 2022 U.S. corn
prices would increase by $0.15 per bushel (4.6%) above the Reference
Case price of $3.19 per bushel. By 2022, U.S. soybean prices would
increase by $0.29 per bushel (2.9%) above the Reference Case price of
$9.97 per bushel. The price of sugarcane would increase $13.34/ton
(41%) above the Reference Case price of $32.49 per ton by 2022. In
2022, beef prices would increase $0.93 per hundred pounds (1.4%),
relative to the Reference Case price of $67.72 per hundred pounds.
Additional price impacts are included in Section 5.1.1 of the DRIA.
Table IX.A.1-2--Change in U.S. Commodity Prices From the Reference Case
[2006$]
------------------------------------------------------------------------
Commodity Change % Change
------------------------------------------------------------------------
Corn......................... $0.15/bushel.................. 4.6
Soybeans..................... $0.29/bushel.................. 2.9
Sugarcane.................... $13.34/ton.................... 41
[[Page 25088]]
Fed Beef..................... $0.93/hundred pounds.......... 1.4
------------------------------------------------------------------------
By 2022, the price of switchgrass is $30.18 per wet ton and the
farm gate feedstock price of corn stover is $32.74/wet ton. These
prices do not include the storage, handling, or delivery costs, which
would result in a delivered price to the ethanol facility of at least
twice the farm gate cost, depending on the region. We intend to update
the costs assumptions (described in more detail in Section 4.1.1 of the
DRIA) for the final rule and invite comment on these assumptions.
2. Impacts on U.S. Farm Income
The increase in renewable fuel production provides a significant
increase in net farm income to the U.S. agricultural sector. FASOM
predicts that net U.S. farm income would increase by $7.1 billion
dollars in 2022 (10.6%), relative to the AEO 2007 Reference Case.
3. Commodity Use Changes
Changes in the consumption patterns of U.S. corn can be seen by the
increasing percentage of corn used for ethanol. FASOM estimates the
amount of domestically produced corn used for ethanol in 2022 would
increase to 33%, relative to the 28% usage rate under the Reference
Case. The rising price of corn and soybeans in the U.S. would also have
a direct impact on how corn is used. Higher domestic corn prices would
lead to lower U.S. exports as the world markets shift to other sources
of these products or expand the use of substitute grains. FASOM
estimates that U.S. corn exports would drop 263 million bushels (-9.9%)
to 2.4 billion bushels by 2022. In value terms, U.S. exports of corn
would fall by $487 million (-5.7%) to $8 billion in 2022.
U.S. exports of soybeans would also decrease under this proposal.
FASOM estimates that U.S. exports of soybeans would decrease 96.6
million bushels (-9.3%) to 943 million bushels by 2022. In value terms,
U.S. exports of soybeans would decrease by $691 million (-6.7%) to $9.7
billion in 2022.
Table IX.A.3-1--Reductions in U.S. Exports From the Reference Case in
2022
------------------------------------------------------------------------
Exports Change % Change
------------------------------------------------------------------------
Corn in Bushels................... 263 million......... -9.9
Soybeans in Bushels............... 96.6 million........ -9.3
------------------------------------------------------------------------
Total Value of Exports Change % Change
------------------------------------------------------------------------
Corn (2006$)...................... $487 million........ -5.7
Soybeans (2006$).................. $691 million........ -6.7
------------------------------------------------------------------------
Higher U.S. demand for corn for ethanol production would cause a
decrease in the use of corn for U.S. livestock feed. Substitutes are
available for corn as a feedstock, and this market is price sensitive.
Several ethanol processing byproducts could also be used to replace a
portion of the corn used as feed, depending on the type of animal.
Distillers dried grains with solubles (DDGS) are a byproduct of dry
milling ethanol production, and gluten meal and gluten feed are
byproducts of wet milling ethanol production. By 2022, FASOM predicts
ethanol byproducts used in feed would increase 19% to 30 million tons,
compared to 25 million tons under the Reference Case.
Table IX.A.3-2--Percent Change in Ethanol Byproducts Use in Feed
Relative to the Reference Case
------------------------------------------------------------------------
Category 2022
------------------------------------------------------------------------
Ethanol Byproducts......................................... 19%
------------------------------------------------------------------------
The EISA cellulosic ethanol requirements result in the production
of residual agriculture products as well as dedicated energy crops. By
2022, FASOM predicts production of 90 million tons of corn residue and
18 million tons of switchgrass. Sugarcane bagasse for cellulosic
ethanol production increases by 15.7 million tons to 19.7 million tons
in 2022 relative to the Reference Case.
4. U.S. Land Use Changes
Higher U.S. corn prices would have a direct impact on the value of
U.S. agricultural land. As demand for corn and other farm products
increases, the price of U.S. farm land would also increase. Our
analysis shows that land prices would increase by about 21% by 2022,
relative to the Reference Case. FASOM estimates an increase of 3.2
million acre increase (3.9%) in harvested corn acres, relative to 83.4
million acres harvested under the Reference Case by 2022.\477\ Most of
the new corn acres come from a reduction in existing crop acres, such
as rice, wheat, and hay.
---------------------------------------------------------------------------
\477\ Total U.S. planted acres increases to 92.2 million acres
from the Reference Case level of 89 million acres in 2022.
---------------------------------------------------------------------------
Though demand for biodiesel increases, FASOM predicts a fall in
U.S. soybean acres harvested, assuming soybean-based biodiesel meets
the EISA GHG emission reduction thresholds. According to the model,
harvested soybean acres would decrease by approximately 0.4 million
acres (-0.5%), relative to the Reference Case acreage of 71.5 million
acres in 2022. Despite the decrease in soybean acres in 2022, soybean
oil production would increase by 0.4 million tons (4.0%) by 2022 over
the Reference Case. Additionally, FASOM predicts that soybean oil
exports would decrease 1.3 million tons by 2022 (-52%) relative to the
Reference Case.
As the demand for cellulosic ethanol increases, most of the
production is derived from corn residue harvesting. As demand for
cellulosic ethanol from bagasse increases, sugarcane acres increase by
0.7 millions acres (55%) to 1.9 million acres by 2022. In addition,
some of the cellulosic ethanol comes from switchgrass, which is not
produced under the Reference Case. In the scenario analyzed, 2.8
million acres of switchgrass will be planted by 2022. As described in
Section V, for both the Reference Case and the Control Case, we assume
32 million acres would remain in the Conservation Reserve Program
(CRP). Therefore, some of the new corn, soybean, and switchgrass acres
may be indirectly coming from former CRP land that is not re-enrolled
in the program.
[[Page 25089]]
Table IX.A.4-1--Change in U.S. Crop Acres Relative to the Reference Case
in 2022
[Millions of acres]
------------------------------------------------------------------------
Crop Change % Change
------------------------------------------------------------------------
Corn.......................................... 3.2 3.9
Soybeans...................................... -0.4 -0.5
Sugarcane..................................... 0.7 55
Switchgrass................................... 2.8 N/A
------------------------------------------------------------------------
The additional demand for corn and other crops for biofuel
production also results in increased use of fertilizer in the U.S. In
2022, FASOM estimates that U.S. nitrogen fertilizer use would increase
897 million pounds (3.4%) over the Reference Case nitrogen fertilizer
use of 26.2 billion pounds. In 2022, U.S. phosphorous fertilizer use
would increase by 496 million pounds (8.6%) relative to the Reference
Case level of 5.8 billion pounds.
Table IX.A.4-2--Change in U.S. Fertilizer Use Relative to the Reference
Case
[Millions of pounds]
------------------------------------------------------------------------
Fertilizer Change % Change
------------------------------------------------------------------------
Nitrogen...................................... 897 3.4
Phosphorous................................... 496 8.6
------------------------------------------------------------------------
5. Impact on U.S. Food Prices
Due to higher commodity prices, FASOM estimates that U.S. food
costs \478\ would increase by roughly $10 per person per year by 2022,
relative to the Reference Case.\479\ Total effective farm gate food
costs would increase by $3.3 billion (0.2%) in 2022.\480\ To put these
changes in perspective, average U.S. per capita food expenditures in
2007 were $3,778 or approximately 10% of personal disposable income.
The total amount spent on food in the U.S. in 2007 was $1.14 trillion
dollars.\481\
---------------------------------------------------------------------------
\478\ FASOM does not calculate changes in price to the consumer
directly. The proxy for aggregate food price change is an indexed
value of all food prices at the farm gate. It should be noted,
however, that according to USDA, approximately 80% of consumer food
expenditures are a result of handling after it leaves the farm
(e.g., processing, packaging, storage, marketing, and distribution).
These costs consist of a complex set of variables, and do not
necessarily change in proportion to an increase in farm gate costs.
In fact, these intermediate steps can absorb price increases to some
extent, suggesting that only a portion of farm gate price changes
are typically reflected at the retail level. See http://www.ers.usda.gov/publications/foodreview/septdec00/FRsept00e.pdf.
\479\ These estimates are based on U.S. Census population
projections of 318 million people in 2017 and 330 million people in
2022. See http://www.census.gov/population/www/projections/natsum.html.
\480\ Farm Gate food prices refer to the prices that farmers are
paid for their commodities.
\481\ See www.ers.usda.gov/Briefing/CPIFoodAndExpenditures/Data/table15.htm.
---------------------------------------------------------------------------
6. International Impacts
Changes in the U.S. agriculture economy are likely to have effects
in other countries around the world in terms of trade, land use, and
the global price and consumption of fuel and food. We utilized the
FAPRI model to assess the impacts of the increased use of renewable
fuels in the U.S. on world agricultural markets.
The FAPRI modeling shows that world corn prices would increase by
7.5% to $3.69 per bushel in 2022, relative to the Reference Case. The
impact on world soybean prices is somewhat smaller, increasing 5.6% to
$9.94 per bushel in 2022.
Changes to the global commodity trade markets and world commodity
prices result in changes in international land use. The FAPRI model
provides international change in crop acres as a result of the RFS2
proposal. Brazil has the largest positive change in crop acres in 2022,
followed by the U.S., Nigeria, India, Paraguay, and China. The FAPRI
model estimates that Brazil crop acres increase by 3.1 million acres
(2.0%) to 153.6 million acres relative to the Reference Case. Total
U.S. acres increase by 2.3 million acres (1.0%) in 2022 to 232.6
million acres. Nigeria has an increase in crop acres of 1.5 million
acres (5.9%) to 27.3 million acres in 2022. India's total crop acres
increase by 1.0 million acres (0.3%) to 326 million acres in 2022.
Total crop acres in Paraguay increase by 0.8 million acres (6.9%) to 12
million acres. China's total crop acres increase by 0.4 million acres
(0.2%) to 257.8 million acres in 2022.
BILLING CODE 6560-50-P
[[Page 25090]]
[GRAPHIC] [TIFF OMITTED] TP26MY09.011
The RFS2 proposal results in higher international commodity prices,
which would impact world food consumption.\482\ The FAPRI model
indicates that world consumption of corn for food would decrease by 1.1
million metric tons in 2022 relative to the Reference Case. Similarly,
the FAPRI model estimates that world consumption of wheat for food
would decrease by 0.6 million metric tons in 2022. World consumption of
oil for food (e.g., vegetable oils) decreases 1.8 million metric tons
by 2022. The model also estimates a small change in world meat
consumption, decreasing by 0.3 million metric tons in 2022. When
considering all the food uses included in the model, world food
consumption decreases by 0.9 million metric tons by 2022 (-0.04%).
While FAPRI provides estimates of changes in world food consumption,
estimating effects on global nutrition is beyond the scope of this
analysis.
---------------------------------------------------------------------------
\482\ The food commodities included in the FAPRI model include
corn, wheat, sorghum, barley, soybeans, sugar, peanuts, oils, beef,
pork, poultry, and dairy products.
Table IX.A.6-1--Change in World Food Consumption Relative to the
Reference Case
[Millions of metric tons]
------------------------------------------------------------------------
Category 2022
------------------------------------------------------------------------
Corn....................................................... -1.1
Wheat...................................................... -0.6
Vegetable Oils............................................. -1.8
Meat....................................................... -0.3
------------
Total Food............................................... -0.9
------------------------------------------------------------------------
Additional information on the U.S. agricultural sector and
international trade impacts of this proposal is described in more
detail in the DRIA (Chapter 5).
B. Energy Security Impacts
Increasing usage of renewable fuels helps to reduce U.S. petroleum
imports. A reduction of U.S. petroleum imports reduces both financial
and strategic risks associated with a potential disruption in supply or
a spike in cost of a particular energy source. This reduction in risks
is a measure of improved U.S. energy security. In this section, we
estimate the monetary value of the energy security benefits of the RFS2
mandated volumes in comparison to the Reference Case by estimating the
impact of the expanded use of renewable fuels on U.S. oil imports and
avoided U.S. oil import expenditures. In the second section, a
methodology is described for estimating the energy security benefits of
reduced U.S. oil imports. The final section summarizes the energy
security benefits to the U.S. associated with this proposal.
1. Implications of Reduced Petroleum Use on U.S. Imports
In 2007, U.S. petroleum imports represented 19.5% of total U.S.
imports of all goods and services.\483\ In 2005, the United States
imported almost 60% of the petroleum it consumed. This compares roughly
to 35% of petroleum from imports in 1975.\484\ Transportation accounts
for 70% of the U.S. petroleum consumption. It is clear that petroleum
imports have a significant impact on the U.S. economy. Diversifying
transportation fuels in the U.S. is expected to lower U.S. petroleum
imports. To estimate the impacts of this proposal on the U.S.'s
dependence on
[[Page 25091]]
imported oil, we calculate avoided U.S. expenditures on petroleum
imports.
---------------------------------------------------------------------------
\483\ Bureau of Economic Affairs: ``U.S. International
Transactions, Fourth Quarter of 2007'' by Elena L. Nguyen and
Jessica Melton Hanson, April 2008.
\484\ Davis, Stacy C.; Diegel, Susan W., Transportation Energy
Data Book: 25th Edition, Oak Ridge National Laboratory, U.S.
Department of Energy, ORNL-6974, 2006.
---------------------------------------------------------------------------
For the proposal, EPA analyzed two approaches to estimate the
reductions in U.S. petroleum imports. The first approach utilizes a
model of the U.S. energy sector, the National Energy Modeling System
(NEMS), to quantify the type and volume of reduced petroleum imports
based on supply and demand for specific fuels in a given year. The
National Energy Modeling System (NEMS) is a computer-based, energy-
economy modeling system of U.S. energy markets through the 2030 time
period. NEMS projects U.S. production, imports, conversion,
consumption, and prices of energy; subject to assumptions on world
energy markets, resource availability and costs, behavioral and
technological choice criteria, cost and performance characteristics of
energy technologies, and demographics. NEMS is designed and implemented
by the Energy Information Administration (EIA) of the U.S. Department
of Energy (DOE). For this analysis, the NEMS model was run with the
2007 AEO levels of biofuels in the Reference Case compared with the
biofuel volume RFS2 requirements.
Considering the regional nature of U.S. imports of petroleum
imports, a second approach was utilized as well to estimate the impacts
of the RFS2 proposal on U.S. oil imports. This approach is labeled
``Regional Gasoline Market'' approach. This approach makes the
assumption that one half of the ethanol market is in the Northeast
region of the U.S., which also comprises about half of the nation's
gasoline demand. For this analysis, it is estimated that ethanol would
displace imported gasoline or gasoline blend stocks in the Northeast,
but not elsewhere in the country. Therefore, to derive the portion of
the new renewable fuels which would offset U.S. petroleum imports (and
not impact domestic refinery production), we multiplied the total
volume of petroleum fuel displaced by 50 percent to represent that
portion of the ethanol which would be used in the Northeast, and 50
percent again to only account for that which would offset imports. The
rest of the ethanol, including half of the ethanol presumed to be used
in the Northeast, is presumed to offset domestic gasoline production,
which ultimately offsets crude oil inputs at refineries. Biodiesel and
renewable diesel are presumed to offset domestic diesel fuel
production.
The results shown in Table IX.B.1-1 below reflect the net lifecycle
reductions in U.S. oil imports projected by NEMS. The net lifecycle
reductions include the upstream petroleum used to produce renewable
fuels, gasoline and diesel, as well as the petroleum directly used by
end-users.
Table IX.B.1-1--Net Reductions in Oil Imports in 2022 (NEMS Model
Results)
[Millions of barrels per day]
------------------------------------------------------------------------
Category of reduction 2022
------------------------------------------------------------------------
Imports of Finished Petroleum Products..................... 0.823
Imports of Crude Oil....................................... (0.007)
Total Reduction............................................ 0.815
Percent Reduction.......................................... 6.15%
------------------------------------------------------------------------
The NEMS model projects that for the year 2022 all of the reduction
in petroleum imports comes out of finished petroleum products. NEMS
projects that 91% of the reductions in 2022 come from reduced net
imports of crude oil and finished petroleum products (as compared to a
9% reduction in domestic U.S. production).
The results shown in Table IX.B.1-2 below reflect the net lifecycle
reductions in U.S. oil imports projected by the use of the Regional
Gasoline Market approach detailed above.
Table IX.B.1-2--Net Reductions in Oil Imports in 2022 (Regional Gasoline
Market Approach Results)
[Millions of barrels per day]
------------------------------------------------------------------------
Category of reduction 2022
------------------------------------------------------------------------
Imports of Finished Petroleum Products..................... 0.250
Imports of Crude Oil....................................... 0.637
Total Reduction............................................ 0.887
Percent Reduction.......................................... 6.17%
------------------------------------------------------------------------
The Regional Gasoline Market approach projects that for 2022, 72%
of the petroleum supply displacement (on a volume basis) comes out of
reduced net crude oil imports, and 28% out of net imports of finished
petroleum products (excluding biofuels). Using our two approaches for
projecting total petroleum import reductions (the NEMS and the Regional
Gasoline Market), we estimate that petroleum product imports will fall
between 0.815 to 0.887 million barrels per day in 2022 as a result of
the RFS2 proposal.
Using the NEMS model, we also calculated the change in expenditures
in both U.S. petroleum and ethanol imports with the RFS2 proposal and
compared these with the U.S. trade position measured as U.S. net
exports of all goods and services economy-wide. Changes in fuel
expenditures were estimated by multiplying the changes in gasoline,
diesel, and ethanol net imports by the respective AEO 2008 wholesale
gasoline and distillate price forecasts, and ethanol price forecasts
from the Food and Agricultural Policy Research Institute (FAPRI) for
the specific analysis years. In Table IX.B.1-3, the net expenditures in
reduced petroleum imports and increased ethanol imports are compared to
the total value of U.S. net exports of goods and services for the whole
economy for 2022. The U.S. net exports of goods and services estimates
are taken from Energy Information Administration's Annual Energy
Outlook 2008. We project that avoided expenditures on imported
petroleum products due to this proposal would be roughly $16 billion in
2022. Relative to the 2022 projection, the total avoided expenditures
on liquid transportation fuels are projected to be $12.4 billion with
the RFS2 proposal.
Table IX.B.1-3--Changes in Expenditures on Transportation Fuel Net
Imports
[Billions of 2006$]
------------------------------------------------------------------------
Category 2022
------------------------------------------------------------------------
AEO Total Net Exports..................................... 16
Expenditures on Net Petroleum Imports..................... (15.96)
Expenditures on Net Ethanol and Biodiesel Imports......... 3.52
Net Expenditures on Transportation Fuel Imports........... (12.44)
------------------------------------------------------------------------
2. Energy Security Implications
In order to understand the energy security implications of reducing
U.S. oil imports, EPA has worked with Oak Ridge National Laboratory
(ORNL), which has developed approaches for evaluating the social costs
and energy security implications of oil use. In a new study entitled
``The Energy Security Benefits of Reduced Oil Use, 2006-2015,''
completed in February, 2008, ORNL has updated and applied the
analytical approach used in the 1997 Report ``Oil Imports: An
Assessment of Benefits and Costs.'' 485 486 This new study
is included as part of the record in this rulemaking.\487\
---------------------------------------------------------------------------
\485\ Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and
Russell Lee, Oil Imports: An Assessment of Benefits and Costs, ORNL-
6851, Oak Ridge National Laboratory, November, 1997.
\486\ The 1997 ORNL paper was cited and its results used in DOT/
NHTSA's rules establishing CAFE standards for 2008 through 2011
model year light trucks. See DOT/NHTSA, Final Regulatory Impacts
Analysis: Corporate Average Fuel Economy and CAFE Reform MY 2008-
2011, March 2006.
\487\ Leiby, Paul N. ``Estimating the Energy Security Benefits
of Reduced U.S. Oil Imports,'' Oak Ridge National Laboratory, ORNL/
TM-2007/028, Final Report, 2008.
---------------------------------------------------------------------------
[[Page 25092]]
The approach developed by ORNL estimates the incremental benefits
to society, in dollars per barrel, of reducing U.S. oil imports, called
the ``oil premium.'' Since the 1997 publication of the ORNL Report,
changes in oil market conditions, both current and projected, suggest
that the magnitude of the oil premium has changed. Significant driving
factors that have been revised include: Oil prices, current and
anticipated levels of OPEC production, U.S. import levels, the
estimated responsiveness of regional oil supplies and demands to price,
and the likelihood of oil supply disruptions. For this analysis, oil
prices from the AEO 2007 were used. Using the ``oil premium'' approach,
the analysis calculates estimates of benefits of improved energy
security from reduced U.S. oil imports due to this proposal.
When conducting this analysis, ORNL considered the full economic
cost of importing petroleum into the U.S. The full economic cost of
importing petroleum into the U.S. is defined for this analysis to
include two components in addition to the purchase price of petroleum
itself. These are: (1) The higher costs for oil imports resulting from
the effect of U.S. import demand on the world oil price and OPEC market
power (i.e., the ``demand'' or ``monopsony'' costs); and (2) the risk
of reductions in U.S. economic output and disruption of the U.S.
economy caused by sudden disruptions in the supply of imported oil to
the U.S. (i.e., macroeconomic disruption/adjustment costs). Maintaining
a U.S. military presence to help secure stable oil supply from
potentially vulnerable regions of the world was excluded from this
analysis because its attribution to particular missions or activities
is difficult.
Also excluded from the prior analysis was risk-shifting that might
occur as the U.S. reduces its dependency on petroleum and increases its
use of biofuels. The analysis to date focused on the potential for
biofuels to reduce oil imports, and the resulting implications of lower
imports for energy security. The Agency recognizes that as the U.S.
relies more heavily on biofuels, such as corn-based ethanol, there
could be adverse consequences from a supply-disruption associated with,
for example, a long-term drought. While the causal factors of a supply-
disruption from imported petroleum and, alternatively, biofuels, are
likely to be unrelated, diversifying the sources of U.S. transportation
fuel will provide energy security benefits. The Agency was not able to
conduct an analysis of biofuel supply disruption issue for this
proposal.
Between today's proposal and the final rulemaking, EPA will attempt
to broaden our energy security analysis to incorporate estimates of
overall motor fuel supply and demand flexibility and reliability, and
impacts of possible agricultural sector market disruptions (for
example, a drought) for presentation in the final rule. The expanded
analysis will also consider how the use of biofuels can alter short and
long run elasticity (flexibility) in the motor fuel market, with
implications for robustness of the fuel system in the face of diverse
supply shocks. As part of this analysis, the Agency plans on analyzing
those factors that can cause shifts in the prices of biofuels, and the
impact these factors have on the energy security estimate.
EPA sponsored an independent-expert peer review of the most recent
ORNL study. A report compiling the peer reviewers' comments is provided
in the docket.\488\ In addition, EPA has worked with ORNL to address
comments raised in the peer review and develop estimates of the energy
security benefits associated with a reduction in U.S. oil imports for
this proposal. In response to peer reviewer comments, EPA modified the
ORNL model by changing several key parameters involving OPEC supply
behavior, the responsiveness of oil demand and supply to a change in
the world oil price, and the responsiveness of U.S. economic output to
a change in the world oil price. EPA is soliciting comments on how to
incorporate additional peer reviewer comments into the ORNL energy
security analysis. (See the DRIA, Chapter 5, for more information on
how EPA responded to peer reviewer comments.)
---------------------------------------------------------------------------
\488\ Peer Review Report Summary: Estimating the Energy Security
Benefits of Reduced U.S. Oil Imports, ICF, Inc., September 2007.
---------------------------------------------------------------------------
With these changes for this proposal, ORNL has estimated that the
total energy security benefits associated with a reduction of imported
oil is $12.38/barrel. Based upon alternative sensitivities about OPEC
supply behavior and the responsiveness of oil demand and supply to a
change in the world oil price, the energy security premium ranged from
$7.65 to $17.23/barrel. Highlights of the analysis are described below.
a. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and
Economic Output
The first component of the full economic costs of importing
petroleum into the U.S. follows from the effect of U.S. import demand
on the world oil price over the long-run. Because the U.S. is a
sufficiently large purchaser of foreign oil supplies, its purchases can
affect the world oil price. This monopsony power means that increases
in U.S. petroleum demand can cause the world price of crude oil to
rise, and conversely, that reduced U.S. petroleum demand can reduce the
world price of crude oil. Thus, one benefit of decreasing U.S. oil
purchases is the potential decrease in the crude oil price paid for all
crude oil purchased. ORNL estimates this component of the energy
security benefit to be $7.65/barrel of U.S. oil imports reduced. A
number of the peer reviewers suggested a variety of ways OPEC and other
oil market participants might react to a decrease in the quantity of
oil purchased by the U.S. ORNL has attempted to reflect a variety of
possible market reactions in the analysis, but continues to evaluate
ways to more explicitly model OPEC and other market participants'
behavior. EPA welcomes comments on this issue. Based upon alternative
sensitivities about OPEC supply behavior, the price-responsiveness of
combined non-OPEC, non-U.S. supply and demand and a lower GDP
elasticity with respect to disrupted oil prices, the monopsony premium
ranged from $3.35-$12.45/barrel of U.S. imported oil reduced.
EPA recognizes that as the world price of oil falls in response to
lower U.S. demand for oil, there is the potential for an increase in
oil use outside the U.S. This so-called international oil ``take back''
or ``rebound'' effect is hard to estimate. Given that oil consumption
patterns vary across countries, there will be different demand
responses to a change in the world price of crude oil. For example, in
Europe, the price of crude oil comprises a much smaller portion of the
overall fuel prices seen by consumers than in the U.S. Since Europeans
pay significantly more than their U.S. counterparts for transportation
fuels, a decline in the price of crude oil is likely to have a smaller
impact on demand. In many other countries, particularly developing
countries, such as China and India, oil is used more widely in
industrial and even electricity applications, although China and
India's energy picture is evolving rapidly. In addition, many countries
around the world subsidize
[[Page 25093]]
their oil consumption. It is not clear how oil consumption would change
due to changes in the market price of oil with the current pattern of
subsidies. Emerging trends in worldwide oil consumption patterns
illustrates the difficulty in trying to estimate the overall effect of
a reduction in world oil price. However, the Agency recognizes that
this effect is important to capture and is examining methodologies for
quantifying this effect. EPA is exploring the development of this
effect at the regional and country level in an effort to capture the
net effect of different drivers. For example, a lower world oil price
might encourage consumption of oil, but a country might deploy programs
and policies discouraging oil consumption, which would have the net
effect of lowering oil consumption to some level less than otherwise
would be expected. EPA solicits comments on how to estimate this
effect.
b. Short-Run Disruption Premium From Expected Costs of Sudden Supply
Disruptions
The second component of the external economic costs resulting from
U.S. oil imports arises from the vulnerability of the U.S. economy to
oil shocks. The cost of shocks depends on their likelihood, size, and
length; the capabilities of the market and U.S. Strategic Petroleum
Reserve (SPR), the largest stockpile of government-owned emergency
crude oil in the world, to respond; and the sensitivity of the U.S.
economy to sudden price increases. While the total vulnerability of the
U.S. economy to oil price shocks depends on the levels of both U.S.
petroleum consumption and imports, variation in import levels or demand
flexibility can affect the magnitude of potential increases in oil
price due to supply disruptions. Disruptions are uncertain events, so
the costs of alternative possible disruptions are weighted by
disruption probabilities. The probabilities used by the ORNL study are
based on a 2005 Energy Modeling Forum \489\ synthesis of expert
judgment and are used to determine an expected value of disruption
costs, and the change in those expected costs given reduced U.S. oil
imports. ORNL estimates this component of the energy security benefit
to be $4.74/barrel of U.S. imported oil reduced. Based upon alternative
sensitivities about OPEC supply behavior, the price-responsiveness of
combined non-OPEC, non-U.S. supply and demand and a lower GDP
elasticity with respect to disrupted oil prices, the macroeconomic
disruption premium ranged from $2.64-$6.96/barrel of U.S. imported oil
reduced. EPA continues to review recent literature on the macroeconomic
disruption premium and welcomes comment on this issue.
---------------------------------------------------------------------------
\489\ Stanford Energy Modeling Forum, Phillip C. Beccue and
Hillard G. Huntington, ``An Assessment of Oil Market Disruption
Risks,'' Final Report, EMF SR 8, October, 2005.
---------------------------------------------------------------------------
c. Costs of Existing U.S. Energy Security Policies
Another often-identified component of the full economic costs of
U.S. oil imports is the cost to the U.S. taxpayers of existing U.S.
energy security policies. The two primary examples are maintaining a
military presence to help secure stable oil supply from potentially
vulnerable regions of the world and maintaining the SPR to provide
buffer supplies and help protect the U.S. economy from the consequences
of global oil supply disruptions.
U.S. military costs are excluded from the analysis performed by
ORNL because their attribution to particular missions or activities is
difficult. Most military forces serve a broad range of security and
foreign policy objectives. Attempts to attribute some share of U.S.
military costs to oil imports are further challenged by the need to
estimate how those costs might vary with incremental variations in U.S.
oil imports. Similarly, while the costs for building and maintaining
the SPR are more clearly related to U.S. oil use and imports,
historically these costs have not varied in response to changes in U.S.
oil import levels. Thus, while SPR is factored into the ORNL analysis,
the cost of maintaining the SPR is excluded.
A majority of the peer reviewers agreed with the exclusion of
military expenditures from the current premium analysis primarily
because of the difficulty in defining and measuring how military
programs and expenditures might respond to incremental changes in U.S.
oil imports. One reviewer clearly opposed including military costs on
principle, and one peer reviewer clearly supported their inclusion if
they could be shown to vary with import levels. The matter of whether
military needs and programs can and do vary with U.S. oil imports or
consumption levels would require careful consideration and analysis. It
also calls for expertise in areas outside the scope of the peer review
such as national security and military affairs. EPA solicits comment in
this area.
d. Anticipated Future Effort
Between the proposal and the final rule, EPA intends to undertake a
variety of actions to improve its energy security premium estimates.
For the monopsony premium, we intend to develop energy security
premiums with alternative AEO oil price cases (e.g., Reference, High,
Low), develop a dynamic analysis methodology (i.e., how the energy
security premium evolves through time), and assess and apply literature
on OPEC strategic behavior/gaming models where possible. For the
macroeconomic disruption impacts, EPA intends to examine recent
literature on the elasticity of GDP to the oil price. Based upon that
literature review, we intend to determine whether there is a difference
in macro disruption impacts in the pre-2000 and post-2000 time period.
Further, we intend to break down the macroeconomic disruption costs by
GDP losses and oil import costs.
EPA solicits comments on the energy security analysis in a number
of areas. Specifically, EPA is requesting comment on its interpretation
of ORNL's results, ORNL's methodology, the monopsony effect, and the
macroeconomic disruption effect.
e. Total Energy Security Benefits
Total annual energy security benefits associated with this proposal
were derived from the estimated reductions in imports of finished
petroleum products and crude oil using an energy security premium price
of $12.38/barrel of reduced U.S. oil imports. Based on these values, we
estimate that the total annual energy security benefits would be $3.7
billion in 2022 (in 2006 dollars).
C. Benefits of Reducing GHG Emissions
1. Introduction
The wider use of renewable fuels from this proposal results in
reductions in greenhouse gas (GHG) emissions. Carbon dioxide
(CO2) and other GHGs mix well in the atmosphere, regardless
of the location of the source, with each unit of emissions affecting
global regional climates; and therefore, influencing regional
biophysical systems. The effects of changes in GHG emissions are felt
for decades to centuries given the atmospheric lifetimes of GHGs. This
section provides estimates for the marginal and total benefits that
could be monetized for the projected GHG emissions reductions of the
proposal. EPA requests comment on the approach utilized to estimate the
GHG benefits associated with the proposal.
2. Marginal GHG Benefits Estimates
The projected net GHG emissions reductions associated with the
proposal reflect an incremental change to projected total global
emissions.
[[Page 25094]]
Therefore, as shown in Section VI.G, the projected global climate
signal will be small but discernable (i.e., incrementally lower
projected distribution of global mean surface temperatures). Given that
the climate response is projected to be a marginal change relative to
the baseline climate, it is conceptually appropriate to use an approach
that estimates the marginal value of changes in climate change impacts
over time as an estimate for the monetized marginal benefit of the GHG
emissions reductions projected for this proposal. The marginal value of
carbon is equal to the net present value of climate change impacts over
hundreds of years of one additional net global metric ton of GHGs
emitted to the atmosphere at a particular point in time. This marginal
value (i.e., cost) of carbon is sometimes referred to as the ``social
cost of carbon.''
Based on the global implications of GHGs and the economic
principles that follow, EPA has developed ranges of global, as well as
U.S., marginal benefits estimates (Table IX.C.2-1).\490\ It is
important to note at the outset that the estimates are incomplete since
current methods are only able to reflect a partial accounting of the
climate change impacts identified by the IPCC (discussed more below).
Also, domestic estimates omit potential impacts on the United States
(e.g., economic or national security impacts) resulting from climate
change impacts in other countries. The global estimates were developed
from a survey analysis of the peer reviewed literature (i.e., meta
analysis). U.S. estimates, and a consistent set of global estimates,
were developed from a single model and are highly preliminary, under
evaluation, and likely to be revised. The latter set of estimates was
developed because the peer reviewed literature does not currently
provide regional (i.e., at the U.S. or China level) marginal benefits
estimates, and it was important to have a consistent set of regional
and global estimates. Ranges of estimates are provided to capture some
of the uncertainties associated with modeling climate change impacts.
---------------------------------------------------------------------------
\490\ For background on economic principles and the marginal
benefit estimates, see Technical Support Document on Benefits of
Reducing GHG Emissions, U.S. Environmental Protection Agency, June
12, 2008, www.regulations.gov (search phrase ``Technical Support
Document on Benefits of Reducing GHG Emissions'').
---------------------------------------------------------------------------
The range of estimates is wide due to the uncertainties relating to
socio-economic futures, climate responsiveness, impacts modeling, as
well as the choice of discount rate. For instance, for 2007 emission
reductions and a 2% discount rate the global meta analysis estimates
range from $-3 to $159/tCO2, while the U.S. estimates range
from $0 to $16/tCO2. For 2007 emission reductions and a 3%
discount rate, the global meta-estimates range from $-4 to $106/
tCO2, and the U.S. estimates range from $0 to $5/
tCO2.\491\ The global meta analysis mean values for 2007
emission reductions are $68 and $40/tCO2 for discount rates
of 2% and 3%, respectively (in 2006 real dollars), while the domestic
mean value from a single model are $4 and $1/tCO2 for the
same discount rates. The estimates for future year emission changes
will be higher as future marginal emissions increases are expected to
produce larger incremental damages as physical and economic systems
become more stressed as the magnitude of climate change increases.\492\
---------------------------------------------------------------------------
\491\ See Table IX.C.1 for global (FUND) estimates consistent
with the U.S. estimates.
\492\ The IPCC suggests an increase of 2-4% per year (IPCC WGII,
2007. Climate Change 2007--Impacts, Adaptation and Vulnerability.
Contribution of Working Group II to the Fourth Assessment Report of
the IPCC, http://www.ipcc.ch/). For Table IX.C.1., we assumed the
estimates increased at 3% per year. For the final rule, we
anticipate that we will explicitly estimate FUND marginal benefits
values for each emissions reduction year.
Table IX.C.2-1--Marginal GHG Benefits Estimates for Discount Rates of 2%, 3%, and 7% and Year of Emissions Change in 2022
[All values are reported in 2006$/tCO2]
--------------------------------------------------------------------------------------------------------------------------------------------------------
2% 3% 7% \b\
--------------------------------------------------------------------------------------------------
Low Central High Low Central High Low Central High
--------------------------------------------------------------------------------------------------------------------------------------------------------
Meta global.......................................... -2 105 247 -2 62 165 n/a n/a n/a
FUND global.......................................... -4 136 1083 -4 26 206 -2 -1 9
FUND domestic........................................ \a\ 0 7 26 \a\ 0 2 9 \a\ 0 \a\ 0 \a\ 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ These estimates, if explicitly estimated, may be greater than zero, especially in later years. They are currently reported as zero because the
explicit estimates for an earlier year were zero and were grown at 3% per year. However, we do not anticipate that the explicit estimates for these
later years would be significantly above zero given the magnitude of the current central estimates for discount rates of 2% and 3% and the effect of
the high discount rate in the case of 7%.
\b\ Except for illustrative purposes, the marginal benefits estimates in the peer reviewed literature do not use consumption discount rates as high as
7%.
The meta analysis ranges were developed from the Tol (2008) meta
analysis. The meta analysis range only includes global estimates
generated by more recent peer reviewed studies (i.e., published after
1995). In addition, the ranges only consider regional aggregations
using simple summation and intergenerational consumption discount rates
of approximately 2% and 3%.\493\ Discount rates of 2% and 3% are
consistent with EPA and OMB guidance on intergenerational discount
rates (EPA, 2000; OMB, 2003).\494\ The estimated distributions of the
meta global estimates are right skewed with long right tails, which is
consistent with characterizations of the low probability high impact
damages (see the DRIA for the estimated probability density functions
by discount rate).\495\ The central meta estimates in Table IX.C.2-1
are means, and the low and high are the 5th and 95th percentiles. Means
are
[[Page 25095]]
presented because, as a central statistic, they better represent the
skewed shape of these distributions compared to medians.
---------------------------------------------------------------------------
\493\ Tol (2008) is an update of the Tol (2005) meta analysis.
Tol (2005) was used in the IPCC Working Group II's Fourth Assessment
Report (IPCC WGII, 2007).
\494\ OMB and EPA guidance on inter-generational discounting
suggests using a low but positive discount rate if there are
important intergenerational benefits/costs. Consumption discount
rates of 1-3% are given by OMB and 0.5-3% by EPA (OMB Circular A-4,
2003; EPA Guidelines for Preparing Economic Analyses, 2000).
\495\ E.g., Webster, M., C. Forest, J.M. Reilly, M.H. Babiker,
D.W. Kicklighter, M. Mayer, R.G. Prinn, M. Sarofim, A.P. Sokolov,
P.H. Stone & C. Wang, 2003. Uncertainty Analysis of Climate Change
and Policy Response, Climatic Change 61(3): 295-320. Also, see
Weitzman, M., 2007, ``The Stern Review of the Economics of Climate
Change,'' Journal of Economic Literature. Weitzman, M., 2007,
``Structural Uncertainty and the Statistical Life in the Economics
of Catastrophic Climate Change,'' Working paper http://econweb.fas.harvard.edu/faculty/weitzman/papers/ValStatLifeClimate.pdf.
---------------------------------------------------------------------------
The consistent domestic and global estimates were developed using
the FUND integrated assessment model (i.e., the Climate Framework for
Uncertainty, Negotiation, and Distribution).\496\ The ranges were
generated from sensitivity analyses where we varied assumptions with
respect to climate sensitivity (1.5 to 6.0 degrees Celsius),\497\ the
socio-economic and emissions baseline scenarios (the FUND default
baseline and three baselines from the Intergovernmental Panel on
Climate Change (IPCC) Special Report on Emissions Scenarios,
SRES),\498\ and the consumption discount rates of approximately 2%, 3%,
and 7%, where 2% and 3% are consistent with intergenerational
discounting.\499\ Furthermore, the model was calibrated to the EPA
value of a statistical life of $7.4 million (in 2006 real
dollars).\500\ The FUND global estimates are the sum of the regional
estimates within FUND. The FUND global and domestic central values in
Table IX.C.2-1 are weighted averages of the FUND estimates from the
sensitivity analysis (see the DRIA for details). The low and high
values are the low and high estimates across the sensitivity runs.
---------------------------------------------------------------------------
\496\ FUND is a spatially and temporally consistent framework--
across regions of the world (e.g., U.S., China), impacts sectors,
and time. FUND explicitly models impacts sectors in 16 global
regions. FUND is one of the few models in the world that explicitly
models global and regional marginal benefits estimates. Numerous
applications of FUND have been published in the peer reviewed
literature dating back to 1997. See http://www.fnu.zmaw.de/FUND.5679.0.html.
\497\ In IPCC reports, equilibrium climate sensitivity refers to
the equilibrium change in the annual mean global surface temperature
following a doubling of the atmospheric equivalent carbon dioxide
concentration. The IPCC states that climate sensitivity is
``likely'' to be in the range of 2 [deg]C to 4.5 [deg]C and
described 3 [deg]C as a ``best estimate'', which is the mode (or
most likely) value. The IPCC goes on to note that climate
sensitivity is ``very unlikely'' to be less than 1.5 [deg]C and
``values substantially higher than 4.5 [deg]C cannot be excluded.''
IPCC WGI, 2007, Climate Change 2007--The Physical Science Basis,
Contribution of Working Group I to the Fourth Assessment Report of
the IPCC, http://www.ipcc.ch/.
\498\ The IMAGE model SRES baseline data was used for the A1b,
A2, and B2 scenarios (IPCC, 2000. Special Report on Emissions
Scenarios. A special report of Working Group III of the
Intergovernmental Panel on Climate Change. Cambridge University
Press, Cambridge).
\499\ The EPA guidance on intergenerational discounting states
that ``[e]conomic analyses should present a sensitivity analysis of
alternative discount rates, including discounting at two to three
percent and seven percent as in the intra-generational case, as well
as scenarios using rates in the interval one-half to three percent
as prescribed by optimal growth models.'' (EPA, 2000).
\500\ This number may be updated to be consistent with recent
EPA regulatory impact analyses that have used a value of $6.4
million (in 2006 real dollars).
---------------------------------------------------------------------------
From Table IX.C.2-1, we see that, in terms of the current monetized
benefits, the domestic marginal benefits are a fraction of the global
marginal benefits. Given uncertainties and omitted impacts, it is
difficult to estimate the actual ratio of total domestic benefits to
total global benefits. The estimates suggest that an emissions
reduction will have direct benefits for current and future U.S.
populations and large benefits for global populations. The long-run and
intergenerational implications of GHG emissions are evident in the
difference in results across discount rates. In the current modeling,
there are substantial long-run benefits (beyond the next two decades to
over 100 years) and some near-term benefits as well as negative effects
(e.g., agricultural productivity and heating demand). High discount
rates give less weight to the distant benefits in the net present value
calculations, and more weight to near-term effects. While not obvious
in Table IX.C.2-1, an additional unit of emissions in the higher
climate sensitivity scenarios, versus the lower climate sensitivity
scenarios, is estimated to have a proportionally larger effect on the
rest of the world compared to the U.S. (see more detailed results in
DRIA). These points are discussed more below.
3. Discussion of Marginal GHG Benefits Estimates
This section briefly discusses important issues relevant to the
marginal benefits estimates in Table IX.C.2-1 (see the DRIA for more
extensive discussion). The broad range of estimates in Table IX.C.2-1
reflects some of the uncertainty associated with estimating monetized
marginal benefits of climate change. The meta analysis range reflects
differences in these assumptions as well as differences in the modeling
of changes in climate and impacts considered and how they were modeled.
EPA considers the meta analysis results to be more robust than the
single model estimates in that the meta results reflect uncertainties
in both models and assumptions.
The current state-of-the-art for estimating benefits is important
to consider when evaluating policies. There are significant partially
unquantified and omitted impact categories not captured in the
estimates provided above. The IPCC WGII (2007) concluded that current
estimates are ``very likely'' to be underestimated because they do not
include significant impacts that have yet to be monetized.\501\ Current
estimates do not capture many of the main reasons for concern about
climate change, including nonmarket damages (e.g., species existence
value and the value of having the option for future use), the effects
of climate variability, risks of potential extreme weather (e.g.,
droughts, heavy rains and wind), socially contingent effects (such as
violent conflict or humanitarian crisis), and thresholds (or tipping
points) associated with species, ecosystems, and potential long-term
catastrophic events (e.g., collapse of the West Antarctic Ice Sheet,
slowing of the Atlantic Ocean Thermohaline Circulation).
Underestimation is even more likely when one considers that the current
trajectory for GHG emissions is higher than typically modeled, which
when combined with current regional population and income trajectories
that are more asymmetric than typically modeled, imply greater climate
change and vulnerability to climate change. See the DRIA for an
initial, partial list of impacts that are currently not modeled in the
FUND model and are thus not reflected in the FUND estimates. EPA is
planning to develop a full assessment of what is not currently being
captured in FUND for the final rule. In addition, EPA plans to quantify
omitted impacts and update impacts currently represented to the maximum
extent possible for the final rule.
---------------------------------------------------------------------------
\501\ IPCC WGII, 2007. In the IPCC report, ``very likely'' was
defined as a greater than 90% likelihood based on expert judgment.
---------------------------------------------------------------------------
The current estimates are also deterministic in that they do not
account for the value people have for changes in risk due to changes in
the likelihood of potential impacts associated with reductions in
CO2 and other GHG emissions (i.e., a risk premium). This is
an issue that has concerned Weitzman and other economists.\502\ We plan
to conduct a formal uncertainty analysis for the final rule to attempt
to account for, to the extent possible, these and other changes in
uncertainty.
---------------------------------------------------------------------------
\502\ E.g, Webster et al., 2003; Weitzman, M., 2007. http://econweb.fas.harvard.edu/faculty/weitzman/papers/ValStatLifeClimate.pdf.
---------------------------------------------------------------------------
The estimates in Table IX.C.2-1 are only relevant for incremental
policies relative to the projected baselines (that do not reflect
potential future climate policies) and there is substantial uncertainty
associated with the estimates themselves both in terms of what is being
modeled and what is not being modeled, with many uncertainties outside
of observed variability.\503\ Both
[[Page 25096]]
of these points are important for non-marginal emissions changes and
estimating total benefits. Also, the uncertainties inherent in this
kind of modeling, including the omissions of many important impacts
categories, present problems for approaches attempting to identify an
economically efficient level of GHG reductions and to positive net
benefit criteria in general, and point to the importance of considering
factors beyond monetized benefits and costs. In uncertain situations
such as that associated with climate, EPA typically recommends that
analysis consider a range of benefit and cost estimates, and the
potential implications of non-monetized and non-quantified benefits.
---------------------------------------------------------------------------
\503\ Because some types of potential climate change impacts may
occur suddenly or begin to increase at a much faster rate, rather
than increasing gradually or smoothly, different approaches are
necessary for quantifying the benefits of ``large'' (non-
incremental) versus ``small'' (incremental) reductions in global
GHGs. Marginal benefits estimates, like those presented above, can
be useful for estimating benefits for small changes in emissions.
See the DRIA for additional discussion of this point. Note that even
small reductions in global GHG emissions are expected to reduce
climate change risks, including catastrophic risks.
---------------------------------------------------------------------------
Economic principles suggest that global benefits should also be
considered when evaluating alternative GHG reduction policies.\504\
Typically, because the benefits and costs of most environmental
regulations are predominantly domestic, EPA focuses on benefits that
accrue to the U.S. population when quantifying the impacts of domestic
regulation. However, OMB's guidance for economic analysis of federal
regulations specifically allows for consideration of international
effects.\505\ GHGs are global and very long-run public goods, and
economic principles suggest that the full costs to society of emissions
should be considered in order to identify the policy that maximizes the
net benefits to society, i.e., achieves an efficient outcome (Nordhaus,
2006).\506\ As such, estimates of global benefits capture more of the
full value to society than domestic estimates and will result in higher
global net benefits for GHG reductions when considered.\507\
---------------------------------------------------------------------------
\504\ Recently, the National Highway Traffic Safety
Administration (NHTSA) issued the final Environmental Impact
Statement for their proposed rulemaking for average fuel economy
standards for passenger cars and light trucks in which the preferred
alternative is based upon a domestic marginal benefit estimate for
carbon dioxide reductions. See Average Fuel Economy Standards,
Passenger Cars and Light Trucks, MY 2011-2015, Final Environmental
Impact Statement http://www.nhtsa.dot.gov/portal/site/nhtsa/menuitem.43ac99aefa80569eea57529cdba046a0/.
\505\ OMB (2003), page 15.
\506\ Nordhaus, W., 2006, ``Paul Samuelson and Global Public
Goods,'' in M. Szenberg, L. Ramrattan, and A. Gottesman (eds),
Samuelsonian Economics, Oxford.
\507\ Both the United Kingdom and the European Commission
following these economic principles in consideration of the global
social cost of carbon (SCC) for valuing the benefits of GHG emission
reductions in regulatory impact assessments and cost-benefit
analyses (Watkiss et al. 2006).
---------------------------------------------------------------------------
Furthermore, international effects of climate change may also
affect domestic benefits directly and indirectly to the extent U.S.
citizens value international impacts (e.g., for tourism reasons,
concerns for the existence of ecosystems, and/or concern for others);
U.S. international interests are affected (e.g., risks to U.S. national
security, or the U.S. economy from potential disruptions in other
nations); and/or domestic mitigation decisions affect the level of
mitigation and emissions changes in general in other countries (i.e.,
the benefits realized in the U.S. will depend on emissions changes in
the U.S. and internationally). The economics literature also suggests
that policies based on direct domestic benefits will result in little
appreciable reduction in global GHGs (e.g., Nordhaus, 1995).\508\ While
these marginal benefits estimates are not comprehensive or economically
optimal, the global estimates in Table IX.C.2-1 internalize a larger
portion of the global and intergenerational externalities of reducing a
unit of emissions.
---------------------------------------------------------------------------
\508\ Nordhaus, William D. (1995). ``Locational Competition and
the Environment: Should Countries Harmonize Their Environmental
Policies?'' in Locational Competition in the World Economy,
Symposium 1994, ed., Horst Siebert, J. C. B. Mohr (Paul Siebeck),
Tuebingen, 1995.
---------------------------------------------------------------------------
A key challenge facing EPA is the appropriate discount rate over
the longer timeframe relevant for GHGs. With the benefits of GHG
emissions reductions distributed over a very long time horizon, benefit
and cost estimations are likely to be very sensitive to the discount
rate. When considering climate change investments, they should be
compared to similar alternative investments (via the discount rate).
Changes in GHG emissions--both increases and reductions--are
essentially long-run investments in changes in climate and the
potential impacts from climate change, which includes the potential for
significant impacts from climate change, where the exact timing and
magnitude of these impacts are unknown.
When there are important benefits or costs that affect multiple
generations of the population, EPA and OMB allow for low but positive
discount rates (e.g., 0.5-3% noted by U.S. EPA, 1-3% by OMB).\509\ In
this multi-generation context, the three percent discount rate is
consistent with observed interest rates from long-term investments
available to current generations (net of risk premiums) as well as
current estimates of the impacts of climate change that reflect
potential impacts on consumers. In addition, rates of three percent or
lower are consistent with long-run uncertainty in economic growth and
interest rates, considerations of issues associated with the transfer
of wealth between generations, and the risk of high impact climate
damages. Given the uncertain environment, analysis could also consider
evaluating uncertainty in the discount rate (e.g., Newell and Pizer,
2001, 2003).\510\
---------------------------------------------------------------------------
\509\ EPA (U.S. Environmental Protection Agency), 2000.
Guidelines for Preparing Economic Analyses. EPA 240-R-00-003. See
also OMB (U.S. Office of Management and Budget), 2003. Circular A-4.
September 17, 2003. These documents are the guidance used when
preparing economic analyses for all EPA rulemakings.
\510\ Newell, R. and W. Pizer, 2001. Discounting the benefits of
climate change mitigation: How much do uncertain rates increase
valuations? PEW Center on Global Climate Change, Washington, DC.
Newell, R. and W. Pizer, 2003. Discounting the distant future: how
much do uncertain rates increase valuations? Journal of
Environmental Economics and Management 46:52-71.
---------------------------------------------------------------------------
For the final rulemaking, we will be developing and updating the
FUND model as best as possible based on the latest research and peer
reviewing the estimates. To improve upon our estimates, we hope to
evaluate several factors not currently captured in the proposed
estimates due to time constraints. For example, we will quantify
additional impact categories as is possible and provide a qualitative
evaluation of the implications of what is not monetized. We also plan
to conduct an uncertainty analysis, consider complementary bottom-up
analyses, and develop estimates of the marginal benefits associated
with non-CO2 GHGs relevant to the rule (e.g.,
CH4, N2O, and HFC-134a).\511\
---------------------------------------------------------------------------
\511\ Due to differences in atmospheric lifetime and radiative
forcing, the marginal benefit values of non-CO2 GHG
reductions and their growth rates over time will not be the same as
the marginal benefits of CO2 emissions reductions (IPCC
WGII, 2007).
---------------------------------------------------------------------------
EPA solicits comment on the appropriateness of using U.S. and
global values in quantifying the benefits of GHG reductions and the
appropriate application of benefits estimates given the state of the
art and overall uncertainties. We also seek comment on our estimates of
the global and U.S. marginal benefits of GHG emissions reductions that
EPA has developed, including the scientific and economic foundations,
the methods employed in developing the estimates, the discount
[[Page 25097]]
rates considered, current and proposed future consideration of
uncertainty in the estimates, marginal benefits estimates for non-
CO2 GHG emissions reductions, and potential opportunities
for improving the estimates. We are also interested in comments on
methods for quantifying benefits for non-incremental reductions in
global GHG emissions.
Because the literature on SCC and our understanding of that
literature continues to evolve, EPA will continue to assess the best
available information on the social cost of carbon and climate
benefits, and may adjust its approaches to quantifying and presenting
information on these areas in future rulemakings.
4. Total Monetized GHG Benefits Estimates
As described in Section VI.F, annualized equivalent GHG emissions
reductions associated with the RFS2 proposal in 2022 would be 160
million metric tons of CO2 equivalent (MMTCO2eq)
with a 2% discount rate, and 155 and 136 MMCO2eq with
discount rates of 3% and 7%, respectively. This section provides the
monetized total GHG benefits estimates associated with the proposal in
2022. As discussed above in Section IX.C.3, these estimates do not
include significant impacts that have yet to be monetized. Total
monetized benefits in 2022 are calculated by multiplying the marginal
benefits per metric ton of CO2 in that year by the
annualized equivalent emissions reductions. For the final rulemaking,
we plan to separate the emissions reductions by gas and use
CO2 and non-CO2 marginal benefits estimates. Non-
CO2 GHGs have different climate and atmospheric implications
and therefore different marginal climate impacts.
Table IX.C.4-1 provides the estimated monetized GHG benefits of the
proposal for 2022. The large range of values in the Table reflects some
of the uncertainty captured in the range of monetized marginal benefits
estimates presented in Table IX.C.2-1.\512\ All values in this section
are presented in 2006 real dollars.
---------------------------------------------------------------------------
\512\ EPA notes, however, that the Ninth Circuit recently
rejected an approach of assigning no monetized value to greenhouse
gas reductions resulting from vehicular fuel economy. Center for
Biodiversity v. NHTSA, F. 3d, (9th Cir. 2007).
Table IX.C.4-1--Monetized GHG Benefits of the Proposed Rule in 2022
[Billion 2006$]
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Marginal benefit 2% 3% 7%
----------------------------------------------------------------------------------------------------------------
Meta global........................... Low..................... -$0.3 -$0.3 n/a
Central................. 16.8 9.6 n/a
High.................... 39.4 25.5 n/a
FUND global........................... Low..................... -0.6 -0.6 -0.3
Central................. 21.7 4.0 -0.1
High.................... 172.8 31.9 1.2
FUND domestic......................... Low..................... 0.0 0.0 0.0
Central................. 1.1 0.3 0.0
High.................... 4.1 1.4 0.0
----------------------------------------------------------------------------------------------------------------
D. Co-pollutant Health and Environmental Impacts
This section describes EPA's analysis of the co-pollutant health
and environmental impacts that can be expected to occur as a result of
this renewable fuels proposal throughout the period from initial
implementation through 2030. GHG emissions are predominantly the
byproduct of fossil fuel combustion processes that also produce
criteria and hazardous air pollutants. The fuels that are subject to
the proposed standard are also significant sources of mobile source air
pollution such as direct PM, NOX, VOCs and air toxics. The
proposed standard would affect exhaust and evaporative emissions of
these pollutants from vehicles and equipment. They would also affect
emissions from upstream sources such as fuel production, storage, and
distribution and agricultural emissions. Any decrease or increase in
ambient ozone, PM2.5, and air toxics associated with the
proposal would impact human health in the form of avoided or incurred
premature deaths and other serious human health effects, as well as
other important public health and welfare effects.
As can be seen in Section II.B, we estimate that the proposal would
lead to both increased and decreased criteria and air toxic pollutant
emissions. Making predictions about human health and welfare impacts
based solely on emissions changes, however, is extremely difficult.
Full-scale photochemical modeling is necessary to provide the needed
spatial and temporal detail to more completely and accurately estimate
the changes in ambient levels of these pollutants. EPA typically
quantifies and monetizes the PM- and ozone-related health and
environmental impacts in its regulatory impact analyses (RIAs) when
possible. However, we were unable to do so in time for this proposal.
EPA attempts to make emissions and air quality modeling decisions early
in the analytical process so that we can complete the photochemical air
quality modeling and use that data to inform the health and
environmental impacts analysis. Resource and time constraints precluded
the Agency from completing this work in time for the proposal. EPA
will, however, provide a complete characterization of the health and
environmental impacts, both in terms of incidence and valuation, for
the final rulemaking.
This section explains what PM- and ozone-related health and
environmental impacts EPA will quantify and monetize in the analysis
for the final rules. EPA will base its analysis on peer-reviewed
studies of air quality and health and welfare effects and peer-reviewed
studies of the monetary values of public health and welfare
improvements, and will be consistent with benefits analyses performed
for the recent analysis of the proposed Ozone NAAQS and the final PM
NAAQS analysis.513 514 These methods will be described in
detail in the DRIA prepared for the final rule.
---------------------------------------------------------------------------
\513\ U.S. Environmental Protection Agency. July 2007.
Regulatory Impact Analysis of the Proposed Revisions to the National
Ambient Air Quality Standards for Ground-Level Ozone. Prepared by:
Office of Air and Radiation. EPA-452/R-07-008.
\514\ U.S. Environmental Protection Agency. October 2006. Final
Regulatory Impact Analysis (RIA) for the Proposed National Ambient
Air Quality Standards for Particulate Matter. Prepared by: Office of
Air and Radiation.
---------------------------------------------------------------------------
Though EPA is characterizing the changes in emissions associated
with toxic pollutants, we will not be able to
[[Page 25098]]
quantify or monetize the human health effects associated with air toxic
pollutants for either the proposal or the final rule analyses. This is
primarily because available tools and methods to assess air toxics risk
from mobile sources at the national scale are not adequate for
extrapolation to benefits assessment. In addition to inherent
limitations in the tools for national-scale modeling of air quality and
exposure, there is a lack of epidemiology data for air toxics in the
general population. For a more comprehensive discussion of these
limitations, please refer to the final Mobile Source Air Toxics
rule.\515\ Please refer to Section VII for more information about the
air toxics emissions impacts associated with the proposed standard.
---------------------------------------------------------------------------
\515\ U.S. Environmental Protection Agency. February 2007.
Control of Hazardous Air Pollutants from Mobile Sources: Final
Regulatory Impact Analysis. Office of Air and Radiation. Office of
Transportation and Air Quality. EPA420-R-07-002.
---------------------------------------------------------------------------
1. Human Health and Environmental Impacts
To model the ozone and PM air quality benefits of the final rules,
EPA will use the Community Multiscale Air Quality (CMAQ) model (see
Section VII.D.2 for a description of the CMAQ model). The modeled
ambient air quality data will serve as an input to the Environmental
Benefits Mapping and Analysis Program (BenMAP).\516\ BenMAP is a
computer program developed by EPA that integrates a number of the
modeling elements used in previous DRIAs (e.g., interpolation
functions, population projections, health impact functions, valuation
functions, analysis and pooling methods) to translate modeled air
concentration estimates into health effects incidence estimates and
monetized benefits estimates.
---------------------------------------------------------------------------
\516\ Information on BenMAP, including downloads of the
software, can be found at http://www.epa.gov/ttn/ecas/benmodels.html.
---------------------------------------------------------------------------
Table IX.D.1-1 lists the co-pollutant health effect exposure-
response functions (PM2.5 and ozone) we will use to quantify
the co-pollutant incidence impacts associated with the proposal.
Table IX.D.1-1--Health Impact Functions Used in BenMAP to Estimate Impacts of PM2.5 and Ozone Reductions
----------------------------------------------------------------------------------------------------------------
Endpoint Pollutant Study Study population
----------------------------------------------------------------------------------------------------------------
Premature Mortality:
Premature mortality--daily O3 Multi-city......... All ages.
time series. Bell et al. (2004)--
Non-accidental.
................. Huang et al.
(2005)--Cardiopulm
onary.
................. Schwartz (2005)--
Non-accidental.
................. Meta-analyses:
................. Bell et al.
(2005)--All
cause.
................. Ito et al.
(2005)--Non-
accidental.
................. Levy et al.
(2005)--All
cause.
Premature mortality--cohort PM2.5 Pope et al. (2002). >29 years.
study, all-cause. Laden et al. (2006) >25 years.
Premature mortality, total PM2.5 Expert Elicitation >24 years.
exposures. (IEc, 2006).
Premature mortality--all-cause... PM2.5 Woodruff et al. Infant (<1 year).
(1997).
Chronic Illness:
Chronic Bronchitis........... PM2.5 Abbey et al. (1995) >26 years.
Nonfatal heart attacks....... PM2.5 Peters et al. Adults (>18 years).
(2001).
Hospital Admissions:
Respiratory.................. O3 Pooled estimate.... >64 years.
................. Schwartz (1995)--
ICD 460-519
(all resp).
................. Schwartz (1994a;
1994b)--ICD 480-
486 (pneumonia).
................. Moolgavkar et
al. (1997)--ICD
480-487
(pneumonia).
................. Schwartz
(1994b)--ICD
491-492, 494-
496 (COPD).
................. Moolgavkar et
al. (1997)--ICD
490-496 (COPD).
................. Burnett et al. <2 years.
(2001).
PM2.5 Pooled estimate.... >64 years.
................. Moolgavkar
(2003)--ICD 490-
496 (COPD).
................. Ito (2003)--ICD
490-496 (COPD).
PM2.5 Moolgavkar (2000)-- 20-64 years.
ICD 490-496 (COPD).
PM2.5 Ito (2003)--ICD 480- >64 years.
486 (pneumonia).
PM2.5 Sheppard (2003)-- <65 years.
ICD 493 (asthma).
Cardiovascular............... PM2.5 Pooled estimate.... >64 years.
................. Moolgavkar
(2003)--ICD 390-
429 (all
Cardiovascular).
................. Ito (2003)--ICD
410-414, 427-
428 (ischemic
heart disease,
dysrhythmia,
heart failure).
PM2.5 Moolgavkar (2000)-- 20-64 years.
ICD 390-429 (all
Cardiovascular).
Asthma-related ER visits..... O3 Pooled estimate.... 5-34 years.
................. Jaffe et al. All ages.
(2003).
................. Peel et al. All ages.
(2005).
................. Wilson et al.
(2005).
PM2.5 Norris et al. 0-18 years.
(1999).
Other Health Endpoints:
[[Page 25099]]
Acute bronchitis............. PM2.5 Dockery et al. 8-12 years.
(1996).
Upper respiratory symptoms... PM2.5 Pope et al. (1991). Asthmatics, 9-11 years.
Lower respiratory symptoms... PM2.5 Schwartz and Neas 7-14 years.
(2000).
Asthma exacerbations......... PM2.5 Pooled estimate.... 6-18 years.
................. Ostro et al.
(2001) (cough,
wheeze and
shortness of
breath).
................. Vedal et al.
(1998) (cough).
Work loss days............... PM2.5 Ostro (1987)....... 18-65 years.
School absence days.......... O3 Pooled estimate.... 5-17 years.
................. Gilliland et al.
(2001).
................. Chen et al.
(2000).
Minor Restricted Activity O3 Ostro and 18-65 years.
Days (MRADs). Rothschild (1989).
PM2.5 Ostro and 18-65 years.
Rothschild (1989).
----------------------------------------------------------------------------------------------------------------
2. Monetized Impacts
Table IX.D.2-1 presents the monetary values we will apply to
changes in the incidence of health and welfare effects associated with
the RFS2 standard.
Table IX.D.2-1--Valuation Metrics Used in BenMAP To Estimate Monetary
Benefits
------------------------------------------------------------------------
Valuation
Endpoint Valuation method (2000$)
------------------------------------------------------------------------
Premature mortality........... Assumed Mean VSL..... $5,500,000
Chronic Illness
Chronic Bronchitis........ WTP: Average Severity 340,482
Myocardial Infarctions, Medical Costs Over 5 .................
Nonfatal. Years. Varies by age
and discount rate.
Russell (1998).
Medical Costs Over 5 .................
Years. Varies by age
and discount rate.
Wittels (1990).
Hospital Admissions
Respiratory, Age 65+...... COI: Medical Costs + 18,353
Wage Lost.
Respiratory, Ages 0-2..... COI: Medical Costs... 7,741
Chronic Lung Disease (less COI: Medical Costs + 12,378
Asthma). Wage Lost.
Pneumonia................. COI: Medical Costs + 14,693
Wage Lost.
Asthma.................... COI: Medical Costs + 6,634
Wage Lost.
Cardiovascular............ COI: Medical Costs + 22,778
Wage Lost (20-64).
COI: Medical Costs + 21,191
Wage Lost (65-99).
ER Visits, Asthma............. COI: Smith et al. 312
(1997).
COI: Standford et al. 261
(1999).
Other Health Endpoints
Acute Bronchitis.......... WTP: 6 Day Illness, 356
CV Studies.
Upper Respiratory Symptoms WTP: 1 Day, CV 25
Studies.
Lower Respiratory Symptoms WTP: 1 Day, CV 16
Studies.
Asthma Exacerbation....... WTP: Bad Asthma Day, 43
Rowe and Chestnut
(1986).
Work Loss Days............ Median Daily Wage, .................
County-Specific.
Minor Restricted Activity WTP: 1 Day, CV 51
Days. Studies.
School Absence Days....... Median Daily Wage, 75
Women 25+.
Worker Productivity....... Median Daily Wage, .................
Outdoor Workers,
County-Specific,
Crocker and Horst
(1981).
Environmental Endpoints WTP: 86 Class I Areas .................
Recreational Visibility.
------------------------------------------------------------------------
Source: Dollar amounts for each valuation method were extracted from
BenMAP version 2.4.5.
3. Other Unquantified Health and Environmental Impacts
In addition to the co-pollutant health and environmental impacts we
will quantify for the analysis of the RFS2 standard, there are a number
of other health and human welfare endpoints that we will not be able to
quantify because of current limitations in the methods or available
data. These impacts are associated with emissions of air toxics
(including benzene, 1,3-butadiene, formaldehyde, acetaldehyde,
acrolein, and ethanol), ambient ozone, and ambient PM2.5
exposures. For example, we have not quantified a number of known or
suspected health effects linked with ozone and PM for which appropriate
health impact functions are not available or which do not provide
easily interpretable outcomes (i.e., changes in heart rate
variability). Additionally, we are currently unable to quantify a
number of known welfare effects, including reduced acid and particulate
deposition damage to cultural monuments and other materials, and
environmental benefits due to reductions of impacts of eutrophication
in coastal areas. For air toxics, the available tools and methods to
assess risk from mobile sources at the national scale are not adequate
for extrapolation to benefits assessment. In addition to inherent
limitations in the
[[Page 25100]]
tools for national-scale modeling of air toxics and exposure, there is
a lack of epidemiology data for air toxics in the general population.
Table IX.D.3-1 lists these unquantified health and environmental
impacts.
Table IX.D.3-1--Unquantified and Non-Monetized Potential Effects
------------------------------------------------------------------------
Effects not included in
Pollutant/Effects analysis--changes in:
------------------------------------------------------------------------
Ozone Health \a\....................... Chronic respiratory damage.
Premature aging of the lungs.
Non-asthma respiratory
emergency room visits.
Exposure to UVb ()
\d\.
Ozone Welfare.......................... Yields for:
--commercial forests.
--some fruits and vegetables.
--non-commercial crops.
Damage to urban ornamental
plants.
Impacts on recreational demand
from damaged forest
aesthetics.
Ecosystem functions.
Exposure to UVb ().
PM Health \b\.......................... Premature mortality--short term
exposures.\c\
Low birth weight.
Pulmonary function.
Chronic respiratory diseases
other than chronic bronchitis.
Non-asthma respiratory
emergency room visits.
Exposure to UVb ().
PM Welfare............................. Residential and recreational
visibility in non-Class I
areas.
Soiling and materials damage.
Damage to ecosystem functions.
Exposure to UVb ().
Nitrogen and Sulfate Deposition Welfare Commercial forests due to
acidic sulfate and nitrate
deposition.
Commercial freshwater fishing
due to acidic deposition.
Recreation in terrestrial
ecosystems due to acidic
deposition.
Existence values for currently
healthy ecosystems.
Commercial fishing,
agriculture, and forests due
to nitrogen deposition.
Recreation in estuarine
ecosystems due to nitrogen
deposition.
Ecosystem functions.
Passive fertilization.
CO Health.............................. Behavioral effects.
Hydrocarbon (HC)/Toxics Health \e\..... Cancer (benzene, 1,3-butadiene,
formaldehyde, acetaldehyde,
ethanol).
Anemia (benzene).
Disruption of production of
blood components (benzene).
Reduction in the number of
blood platelets (benzene).
Excessive bone marrow formation
(benzene).
Depression of lymphocyte counts
(benzene).
Reproductive and developmental
effects (1,3-butadiene,
ethanol).
Irritation of eyes and mucus
membranes (formaldehyde).
Respiratory irritation
(formaldehyde).
Asthma attacks in asthmatics
(formaldehyde).
Asthma-like symptoms in non-
asthmatics (formaldehyde).
Irritation of the eyes, skin,
and respiratory tract
(acetaldehyde).
Upper respiratory tract
irritation and congestion
(acrolein).
HC/Toxics Welfare \f\.................. Direct toxic effects to
animals.
Bioaccumulation in the food
chain.
Damage to ecosystem function.
Odor.
------------------------------------------------------------------------
\a\ In addition to primary economic endpoints, there are a number of
biological responses that have been associated with ozone health
effects including increased airway responsiveness to stimuli,
inflammation in the lung, acute inflammation and respiratory cell
damage, and increased susceptibility to respiratory infection. The
public health impact of these biological responses may be partly
represented by our quantified endpoints.
\b\ In addition to primary economic endpoints, there are a number of
biological responses that have been associated with PM health effects
including morphological changes and altered host defense mechanisms.
The public health impact of these biological responses may be partly
represented by our quantified endpoints.
\c\ While some of the effects of short-term exposures are likely to be
captured in the estimates, there may be premature mortality due to
short-term exposure to PM not captured in the cohort studies used in
this analysis. However, the PM mortality results derived from the
expert elicitation do take into account premature mortality effects of
short term exposures.
\d\ May result in benefits or disbenefits.
\e\ Many of the key hydrocarbons related to this rule are also hazardous
air pollutants listed in the Clean Air Act. Please refer to Section
VII.E.4 for additional information on the health effects of air
toxics.
\f\ Please refer to Section VII.E for additional information on the
welfare effects of air toxics.
While there will be impacts associated with air toxic pollutant
emission changes that result from the RFS2 standard, we will not
attempt to monetize those impacts. This is primarily because currently
available tools and methods to assess air toxics risk from mobile
sources at the national scale are not adequate for extrapolation to
incidence estimations or benefits assessment. The best suite of tools
and methods currently available for assessment at the national scale
are those used in the National-Scale Air Toxics Assessment (NATA). The
EPA Science Advisory Board specifically commented in their review of
the 1996 NATA that these tools were not yet ready for use in a
national-scale benefits analysis, because they did not consider the
full distribution of exposure and risk, or address sub-chronic health
effects.\517\ While EPA has since improved the tools, there remain
critical limitations for estimating incidence and assessing benefits of
reducing mobile source air toxics. EPA continues to work to address
these limitations; however, we do not anticipate having methods and
tools available for national-scale application in time for the analysis
of the final rules. Please refer to the final Mobile Source Air Toxics
Rule RIA for more discussion.\518\
---------------------------------------------------------------------------
\517\ Science Advisory Board. 2001. NATA--Evaluating the
National-Scale Air Toxics Assessment for 1996--an SAB Advisory.
http://www.epa.gov/ttn/atw/sab/sabrev.html.
\518\ U.S. EPA. 2007. Control of Hazardous Air Pollutants From
Mobile Sources--Regulatory Impact Analysis. Assessment and Standards
Division. Office of Transportation and Air Quality. EPA420R-07-002.
February.
---------------------------------------------------------------------------
E. Economy-Wide Impacts
It is anticipated that this proposed rulemaking will have impacts
on the U.S. economy that extend beyond the two sectors most directly
affected--the transportation and agriculture sectors. Consider how the
proposed rulemaking will affect the overall U.S. economy. By requiring
36 billion gallons of renewable transportation fuels in the U.S.
transportation sector by 2022, it is anticipated that the cost of motor
vehicle fuels will increase. This cost increase will impact all sectors
of the economy that use motor vehicles fuels, as intermediate inputs to
production. For example, manufacturing firms will see an increase in
their shipping costs. Households will also be impacted as consumers of
these goods, and directly as consumers of motor vehicle fuels.
Additionally, it is anticipated that the production of renewable fuels
will increase the demand for U.S. farm
[[Page 25101]]
products, and increase farm incomes. This will have ripple effects for
sectors that supply inputs to the U.S. farm sector (e.g. tractors), and
sectors that demand outputs from the farm sector. The sum of all of
these impacts will affect the total levels of output and consumption in
the U.S. economy. Because multiple markets beyond the transportation
sector will be affected by the proposed rulemaking, a general
equilibrium analysis is required to provide a more accurate picture of
the social cost of the policy than a partial equilibrium analysis. (A
partial equilibrium analysis looks at the impacts in one market of the
economy but does not attempt to capture the full interaction of a
policy change in all markets simultaneously, as a general equilibrium
model does).
In order to estimate the impacts of the RFS2 rule on U.S. gross
domestic product (GDP) and consumption, EPA intends to use an economy-
wide, computable general equilibrium (CGE) model between proposal and
the final rule. This model will use detailed fuel sector cost estimates
provided in Section VIII as inputs to determine the economy-wide
impacts of the rulemaking. The economy-wide model to be utilized for
this analysis is the Intertemporal General Equilibrium Model (IGEM).
IGEM is a model of the U.S. economy with an emphasis on the energy and
environmental aspects. It is a dynamic model, which depicts growth of
the economy due to capital accumulation, technical change and
population change. It is a detailed multi-sector model covering thirty-
five industries of the U.S. economy. It also depicts changes in
consumption patterns due to demographic changes, price and income
effects. The substitution possibilities for both producers and
consumers in IGEM are driven by model parameters that are based on
observed market behavior revealed over the past forty to fifty years.
EPA seeks comment on the modeling approach to be utilized to estimate
the economy-wide impacts of the RFS2 proposal.
An additional issue that arises is how biofuel subsidies are
considered from an economy-wide perspective. The Renewable Fuels
Standard, by encouraging the use of biofuels, will result in an
expansion of subsidy payments by the U.S. For example, each gallon of
corn-based ethanol sold in the U.S. qualifies for a $0.45/gallon
subsidy. One assumption that could be made is that biofuel subsidies,
which are a loss in revenue to the U.S. government, are offset by an
increase in taxes by the U.S. In this case, the Renewable Fuels
Standard program becomes revenue neutral. If taxes are raised to offset
the revenue loss from the subsidies, the taxes could have a
distortionary impact on the economy. For example, if taxes are raised
on labor and capital, then there will less output. To account for the
potential distortionary impacts of increased taxes, as a rule of thumb,
it is sometimes assumed that for each dollar of tax revenue raised,
there is a $0.25 loss in output in the economy. We intend to consider
the impact of the expansion of biofuel subsidies from the RFS2 in the
context of the economy-wide modeling.
X. Impacts on Water
A. Background
As the production and price of corn and other biofuel feedstocks
increase, there may be substantial impacts to both water quality and
water quantity. To analyze the potential water-related impacts, EPA
focused on agricultural corn production for several reasons. Corn acres
have increased dramatically, 20% in 2007. Although corn acres declined
seven percent in 2008, total corn acres remained the second highest
since 1946.\519\ Corn has the highest fertilizer and pesticide use per
acre and accounts for the largest share of nitrogen fertilizer use
among all crops.\520\ Corn generally utilizes only 40 to 60% of the
applied nitrogen fertilizer. The remaining nitrogen is available to
leave the field and runoff to surface waters, leach into ground water,
or volatilize to the air where it can return to water through
depositional processes.
---------------------------------------------------------------------------
\519\ U.S. Department of Agriculture, National Agricultural
Statistics Service, ``Acreage'', 2008, available online at: http://usda.mannlib.cornell.edu/usda/current/Acre/Acre-06-30-2008.pdf.
\520\ Committee on Water Implications of Biofuels Production in
the United States, National Research Council, 2008, Water
implications of biofuels production in the United States, The
National Academies Press, Washington, DC, 88 p.
---------------------------------------------------------------------------
There are three major pathways for contaminants to reach water from
agricultural lands: run off from the land's surface, subsurface tile
drains, or leaching to ground water. A variety of management factors
influence the potential for contaminants such as fertilizers, sediment,
and pesticides to reach water from agricultural lands. These factors
include nutrient and pesticide application rates and application
methods, use of conservation practices and crop rotations by farmers,
and acreage and intensity of tile drained lands.
Historically, corn has been grown in rotation with other crops,
especially soybeans. As corn prices increase relative to prices for
other crops, more farmers are choosing to grow corn every year
(continuous corn). Continuous corn production results in significantly
greater nitrogen losses annually than a corn-soybean rotation and lower
yields per acre. In response, farmers may add higher rates of nitrogen
fertilizer to try to match yields of corn grown in rotation. Growing
continuous corn also increases the viability of pests such as corn
rootworm. Farmers may increase use of pesticides to control these
pests. As corn acres increase, use of the common herbicides like
atrazine and glyphosate (e.g. Roundup) may also increase.
High corn prices may encourage farmers to grow corn on lands that
are marginal for row production such as hay land or pasture. Typically,
agricultural producers apply far less fertilizer and pesticide on
pasture land than land in row crops. Corn yield on these marginal lands
will be lower and may require higher fertilizer rates. However since
nitrogen fertilizer prices are tied to oil prices, fertilizer costs
have increased significantly recently. It is unclear how agricultural
producers have responded to these increases in both corn and fertilizer
prices. EPA solicits comments on the impact of corn and fertilizer
prices on nitrogen fertilizer use.
Tile drainage is another important factor in determining the losses
of fertilizer from cropland. Tile drainage consists of subsurface tiles
or pipes that move water from wet soils to surface waters quickly so
crops can be planted. Tile drainage has transformed large expanses of
historic wetland soils into productive agriculture lands. However, the
tile drains also move fertilizers and pesticides more quickly to
surface waters without any of the attenuation that would occur if these
contaminants moved through soils or wetlands. The highest proportion of
tile drainage occurs in the Upper Mississippi and the Ohio-Tennessee
River basins.\521\
---------------------------------------------------------------------------
\521\ U.S. Environmental Protection Agency, EPA Science Advisory
Board, Hypoxia in the northern Gulf of Mexico, EPA-SAB-08-003, 275
p, available online at: http://yosemite.epa.gov/sab/sabproduct.nsf/
C3D2F27094E03F90852573B800601D93/$File/EPA-SAB-08-
003complete.unsigned.pdf.
---------------------------------------------------------------------------
The increase in corn production and prices may also have
significant impacts on voluntary conservation programs funded by the
U.S. Department of Agriculture (USDA) that are important to protect
water quality. As land values increase due to higher crop prices, USDA
payments may not keep up with the need for farmers and tenant farmers,
to make an adequate return. For example, farmland in Iowa increased an
[[Page 25102]]
average of 18% in 2007 from 2006 prices.
Both land retirement programs like the Conservation Reserve Program
(CRP) and working land programs like the Environmental Quality
Incentives Program (EQIP) can be affected. Under CRP, USDA contracts
with farmers to take land out of agricultural production and plant
grasses or trees. Generally farmers put land into CRP because it is not
as productive and has other characteristics that make the cropland more
environmentally sensitive, such as high erosion rates. CRP provides
valuable environmental benefits both for water quality and for wildlife
habitat. Midwestern states, where much of U.S. corn is grown, tend to
have lower CRP reenrollment rates than the national average. Under
EQIP, USDA makes cost-share payments to farmers to implement
conservation practices. Some of the most cost-effective practices
include: Riparian buffers; crop rotation; appropriate rate, timing, and
method of fertilizer application; cover crops; and, on tile-drained
lands, treatment wetlands and controlled drainage. Producers may be
less willing to participate and require higher payments to offset
perceived loss of profits through implementation of conservation
practices.
1. Ecological Impacts
Nitrogen and phosphorus enrichment due to human activities is one
of the leading problems facing our nation's lakes, reservoirs, and
estuaries. Nutrient enrichment also has negative impacts on aquatic
life in streams; adverse health effects on humans and domestic animals;
and impairs aesthetic and recreational use. Excess nutrients can lead
to excessive growth of algae in rivers and streams, and aquatic plants
in all waters. For example, declines in invertebrate community
structure have been correlated directly with increases in phosphorus
concentration. High concentrations of nitrogen in the form of ammonia
are known to be toxic to aquatic animals. Excessive levels of algae
have also been shown to be damaging to invertebrates. Finally, fish and
invertebrates will experience growth problems and can even die if
either oxygen is depleted or pH increases are severe; both of these
conditions are symptomatic of eutrophication. As a biologic system
becomes more enriched by nutrients, different species of algae may
spread and species composition can shift.
Nutrient pollution is widespread. The most widely known examples of
significant nutrient impacts include the Gulf of Mexico and the
Chesapeake Bay. There are also known impacts in over 80 estuaries/bays,
and thousands of rivers, streams, and lakes. Waterbodies in virtually
every state and territory in the U.S. are impacted by nutrient-related
degradation. Reducing nutrient pollution is a priority for EPA. The
combustion of transportation fuels results in significant loadings of
nitrogen from air deposition to waterbodies around the country,
including the Chesapeake Bay, Long Island Sound, and Lake Tahoe.
2. Gulf of Mexico
Production of corn for ethanol may exacerbate existing serious
water quality problems in the Gulf of Mexico. Nitrogen fertilizer
applications to corn are already the major source of total nitrogen
loadings to the Mississippi River. A large area of low oxygen, or
hypoxia, forms in the Gulf of Mexico every year, often called the
``dead zone.'' The primary cause of the hypoxia is excess nutrients
(nitrogen and phosphorus) from the Upper Midwest flowing into the
Mississippi River to the Gulf. These nutrients trigger excessive algal
growth (or eutrophication) resulting in reduced sunlight, loss of
aquatic habitat, and a decrease in oxygen dissolved in the water.
Hypoxia threatens commercial and recreational fisheries in the Gulf
because fish and other aquatic species cannot live in the low oxygen
waters.
In 2008, the hypoxic zone was the second largest since measurements
began in 1985--8,000 square miles, an area larger than the state of
Massachusetts, and slightly larger than the 2007 measurement.\522\ The
Mississippi River/Gulf of Mexico Watershed Nutrient Task Force's ``Gulf
Hypoxia Action Plan 2008'' calls for a 45% reduction in both nitrogen
and phosphorus reaching the Gulf to reduce the size of the zone.\523\
An additional reduction in nitrogen and phosphorus reduction would be
necessary as a result of increased corn production for ethanol and
climate change impacts.
---------------------------------------------------------------------------
\522\ Louisiana Universities Marine Consortium, 2008, `Dead
zone' again rivals record size, available online at: http://www.gulfhypoxia.net/research/shelfwidecruises/2008/PressRelease08.pdf.
\523\ Mississippi River/Gulf of Mexico Watershed Nutrient Task
Force, 2008, Gulf hypoxia action plan 2008 for reducing, mitigating,
and controlling hypoxia in the northern Gulf of Mexico and improving
water quality in the Mississippi River basin, 61 p., Washington, DC,
available online at: http://www.epa.gov/msbasin/actionplan.htm.
---------------------------------------------------------------------------
Alexander, et al.\524\ modeled the sources of nutrient loadings to
the Gulf of Mexico using the USGS SPARROW model. They estimated that
agricultural sources contribute more than 70% of the delivered nitrogen
and phosphorus. Corn and soybean production accounted for 52% of
nitrogen delivery and 25% of the phosphorus.
---------------------------------------------------------------------------
\524\ Alexander, R.B., Smith, R.A., Schwarz, G.E., Boyer, E.W.,
Nolan, J.V., and Brakebill, J.W., 2008, Differences in phosphorus
and nitrogen delivery to the Gulf of Mexico from the Mississippi
River basin, Environmental Science and Technology, v. 42, no. 3, p.
822-830, available online at: http://pubs.acs.org/cgi-bin/abstract.cgi/esthag/2008/42/i03/abs/es0716103.html.
---------------------------------------------------------------------------
Several recent scientific reports have estimated the impact of
increasing corn acres for ethanol in the Gulf of Mexico watershed.
Donner and Kucharik's \525\ study showed increases in nitrogen export
to the Gulf as a result of increasing corn ethanol production from 2007
levels to 15 billion gallons in 2022. They concluded that the expansion
of corn-based ethanol production could make it almost impossible to
meet the Gulf of Mexico nitrogen reduction goals without a ``radical
shift'' in feed production, livestock diet, and management of
agricultural lands. The study estimated a mean dissolved inorganic
nitrogen load increase of 10 to 18% from 2007 to 2022 to meet the 15
billion gallon corn ethanol goal. EPA's Science Advisory Board report
to the Mississippi River/Gulf of Mexico Watershed Task Force estimated
that corn grown for ethanol will result in an additional national
annual loading of almost 300 million pounds of nitrogen. An estimated
80% of that nitrogen loading or 238 million pounds will occur in the
Mississippi-Atchafalaya River basin and contribute nitrogen to the
hypoxia in the Gulf of Mexico.\526\
---------------------------------------------------------------------------
\525\ Donner, S. D. and Kucharik, C. J., 2008, Corn-based
ethanol production compromises goal of reducing nitrogen export by
the Mississippi River, PNAS, v. 105, no. 11, p. 4513-4518, available
online at: http://www.pnas.org/content/105/11/4513.full.
\526\ U.S. EPA, supra note 4.
---------------------------------------------------------------------------
B. Upper Mississippi River Basin Analysis
To provide a quantitative estimate of the impact of this proposal
and production of corn ethanol generally on water quality, EPA
conducted an analysis that modeled the changes in loadings of nitrogen,
phosphorus, and sediment from agricultural production in the Upper
Mississippi River Basin (UMRB). The UMRB drains approximately 189,000
square miles, including large parts of the states of Illinois, Iowa,
Minnesota, Missouri, and Wisconsin. Small portions of Indiana,
Michigan, and South Dakota are also within the basin. EPA selected the
UMRB because it is representative of the many potential issues
associated with ethanol production, including its connection to major
water quality
[[Page 25103]]
concerns such as Gulf of Mexico hypoxia, large corn production, and
numerous ethanol production plants. For more details on the analysis,
see Chapter 6 in the DRIA.
On average the UMRB contributes about 39% of the total nitrogen
loads and 26% of the total phosphorus loads to the Gulf of Mexico.\527\
The high percentage of nitrogen from the UMRB is primarily due to the
large inputs of fertilizer for agriculture and the 60% of cropland that
is tile drained. Although nitrogen inputs to the UMRB in recent years
is fairly level, there is a 21% decline in net inputs from humans. The
Science Advisory Board report attributes this decline to higher amount
of nitrogen removed during harvest, due to higher crop yields. For the
same time period, phosphorus inputs increased 12%.
---------------------------------------------------------------------------
\527\ Mississippi River/Gulf of Mexico Watershed Nutrient Task
Force, supra note 6.
---------------------------------------------------------------------------
1. SWAT Model
EPA selected the SWAT (Soil and Water Assessment Tool) model to
assess nutrient loads from changes in agricultural production in the
UMRB. Models are the primary tool that can be used to predict future
impacts based on alternative scenarios. SWAT is a physical process
model developed to quantify the impact of land management practices in
large, complex watersheds.\528\
---------------------------------------------------------------------------
\528\ Gassman, P.W., Reyes, M.R., Green, C.H., Arnold, J.G.,
2007, The soil and water assessment tool: Historical development,
applications, and future research directions. Transactions of the
American Society of Agricultural and Biological Engineers, v. 50,
no. 4, p. 1211-1240. http://www.card.iastate.edu/environment/items/asabe_swat.pdf.
---------------------------------------------------------------------------
2. Baseline Model Scenario
In order to assess alternative potential future conditions within
the UMRB, EPA developed a SWAT model of a Baseline Scenario against
which to analyze the impact of increased corn production for biofuel.
For simplicity's sake, we refer to the baseline as 2005, but like most
water quality modeling, we had to use a range of data sets for the
inputs. As noted above corn acres did not increase significantly until
the 2007 crop year. While this baseline does not directly quantify the
impacts of this proposal on water quality, it is useful in
understanding the magnitude of the impacts of corn production for
biofuels. EPA plans to conduct additional analyses for the final rule
that will compare the reference case biofuel volumes to the RFS2
volumes.
The SWAT model was applied (i.e., calibrated) to the UMRB using
1960 to 2001 weather data and flow and water quality data from 13 USGS
gages on the mainstem of the Mississippi River. The 42-year SWAT model
runs were performed and the results analyzed to establish runoff,
sediment, nitrogen, and phosphorous loadings from each of the 131 8-
digit HUC subwatersheds and the larger 4-digit subbasins, along with
the total outflow from the UMRB and at the various USGS gage sites
along the Mississippi River. These results provided the Baseline
Scenario model values to which the future alternatives are compared.
3. Alternative Scenarios
SWAT scenario analyses were performed for the years 2010, 2015,
2020, and 2022 with corn ethanol volumes of 12 billion gallons a year
(BGY) for 2010, and 15 BGY for 2015 to 2022. These volumes were
adjusted for the UMRB based on a 42.3% ratio of ethanol production
capacity within the UMRB compared to national capacity. The resulting
UMRB ethanol production goals were converted into the corresponding
required corn production acreage, i.e. the extent of corn acreage
needed to meet those ethanol production goals. Annual increases in corn
yield of 1.23% were built into the future scenarios. Fewer corn acres
were needed to meet ethanol production goals after the 2015 scenario
due to those yield increases.
Table X.B.3-1 and Table X.B.3-2 summarize the model outputs both
within the UMRB and at the outlet of the UMRB in the Mississippi River
at Grafton, Illinois for each of the four scenario years: 2010, 2015,
2020, and 2022. It is important to note that these results only
estimate loadings from the Upper Mississippi River basin, not the
entire Mississippi River watershed. As noted earlier, the UMRB
contributes about 39% of the total nitrogen loads and 26% of total
phosphorus loads to the Gulf of Mexico. Due to the timing of this
proposal, we were not able to assess the local impact in smaller
watersheds within the UMRB. Those impacts may be significantly
different. The decreasing nitrogen load over time is likely attributed
to the increased corn yield production, resulting in greater plant
uptake of nitrogen.
Table X.B.3-1--Changes in Nutrient Loadings Within the Upper Mississippi River Basin From the 2005 Baseline
Scenario
----------------------------------------------------------------------------------------------------------------
2005 Baseline 2010 2015 2020 2022
----------------------------------------------------------------------------------------------------------------
Nitrogen................................ 1897.0 million lbs........ +5.1% +4.2% +2.2% +1.6%
Phosphorus.............................. 176.6 million lbs......... +2.3% +1.1% +0.6% +0.4%
----------------------------------------------------------------------------------------------------------------
About 24% of nitrogen and 25% of phosphorus leaving agricultural
fields was assimilated (taken by aquatic plants or volatilized) before
reaching the outlet of the UMRB. The assimilated nitrogen is not
necessarily eliminated as an environmental concern. Five percent or
more of the nitrogen can be converted to nitrous gas, a powerful
greenhouse gas that has 300 times the climate-warming potential of
carbon dioxide, the major greenhouse. Thus, a water pollutant becomes
an air pollutant until it is either captured through biological
sequestration or converted fully to elemental nitrogen.
Total sediment outflow showed very little change over all
scenarios. This is likely due to the corn being modeled as well-managed
crop in terms of sediment loss, primarily due to the corn stover
remaining on the fields following harvest.
Table X.B.3-2--Changes From the 2005 Baseline to the Mississippi River at Grafton, Illinois From the Upper
Mississippi River Basin
----------------------------------------------------------------------------------------------------------------
2005 Baseline 2010 2015 2020 2022
----------------------------------------------------------------------------------------------------------------
Average corn yield (bushels/acre)....... 141....................... 150 158 168 171
[[Page 25104]]
Nitrogen................................ 1,433.5 million lbs....... +5.5% +4.7% +2.5% +1.8%
Phosphorus.............................. 132.4 million lbs......... +2.8% +1.7% +0.98% +0.8%
Sediment................................ 6.4 million tons.......... +0.5% +0.3% +0.2% +0.1%
----------------------------------------------------------------------------------------------------------------
After evaluating comments on this proposal, if time and resources
permit, EPA may conduct additional water quality analyses using the
SWAT model in the UMRB. Potential future analyses could include: (1)
Determination of the most sensitive assumptions in the model, (2) water
quality impacts from the changes in ethanol volumes between the
reference case and this proposal, (3) removing corn stover for
cellulosic ethanol, and (4) a case study of a smaller watershed to
evaluate local water quality impacts that are impossible to ascertain
at the scale of the UMRB.
EPA solicits comments on the scenarios developed for this proposal
and additional future analyses. At this time, we are not able to assess
the impact of these additional loadings on the size of the Gulf of
Mexico hypoxia zone or water quality within the UMRB. EPA also solicits
comments on the significance of the modeled increases in nitrogen and
phosphorus loads.
C. Additional Water Issues
Water quality and quantity impacts resulting from corn ethanol
production go beyond our ability to model. The following issues are
summarized to provide additional context about the broader range of
potential impacts. See Chapter 6 in the DRIA for more discussion of
these issues.
1. Chesapeake Bay Watershed
Agricultural lands contribute more nutrients to the Chesapeake Bay
than any other land use. Chesapeake Bay Program partners have pledged
to significantly reduce nutrients to the Bay to meet water quality
goals. To estimate the increase in nutrient loads to the Bay from
changes to agricultural crop production from 2005 to 2008, the
Chesapeake Bay Program Watershed Model Phase 4.3 and Vortex models were
utilized. Total nitrogen loads increased by almost 2.4 million pounds
from an increase of almost 66,000 corn acres. As agriculture land use
shifts from hay and pasture to more intensively fertilized row crops,
this analysis estimates that nitrogen loads increase by 8.8 million
pounds.
2. Ethanol Production
There are three principal sources of discharges to water from
ethanol plants: Reject water from water purification, cooling water
blowdown, and off-batch ethanol. Most ethanol facilities use on-site
wells to produce the process water for the ethanol process. Groundwater
sources are generally not suitable for process water because of their
mineral content. Therefore, the water must be treated, commonly by
reverse osmosis. For every two gallons of pure water produced, about a
gallon of brine is discharged as reject water from this process. Most
estimates of water consumption in ethanol production are based on the
use of clean process water and neglect the water discharged as reject
water.
The largest source of wastewater discharge is reverse osmosis
reject water from process water purification. The reverse osmosis
process concentrates groundwater minerals to levels where they can have
water quality impacts. There is really no means of ``treating'' these
ions to reduce toxicity, other than further concentration and disposal,
or use of instream dilution. Some facilities have had to construct long
pipelines to get access to dilution so they can meet water quality
standards. Ethanol plants also discharge cooling water blowdown, where
some water is discharged to avoid the buildup of minerals in the
cooling system. These brines are similar to the reject water described
above. In addition, if off-batch ethanol product or process water is
discharged, the waste stream can have high Biochemical Oxygen Demand
(BOD) levels. BOD directly affects the amount of dissolved oxygen in
rivers and streams. The greater the BOD, the more rapidly oxygen is
depleted in the stream. The consequences of high BOD are the same as
those for low dissolved oxygen: Aquatic organisms become stressed,
suffocate, and die.
Older generation production facilities used four to six gallons of
process water to produce a gallon of ethanol, but newer facilities use
less than three gallons of water in the production process. Most of
this water savings is gained through improved recycling of water and
heat in the process. Water supply is a local issue, and there have been
concerns with water consumption as new plants go online. Some
facilities are tapping into deeper aquifers as a source of water. These
deeper water resources tend to contain higher levels of minerals and
this can further increase the concentration of minerals in reverse
osmosis reject water. Geographic impacts of water use vary. A typical
plant producing 50 million gallons of ethanol per year uses a minimum
of 175 million gallons of water annually. In Iowa, water consumption
from ethanol refining accounts for about seven percent of all
industrial water use, and is projected to be 14% by 2012--or about 50
million gallons per day.
a. Distillers Grain with Solubles
Distillers grain with solubles (DGS) is an important co-product of
ethanol production. About one-third of the corn processed into ethanol
is converted into DGS. DGS has become an increasingly important feed
component for confined livestock. DGS are higher in crude protein
(nitrogen) and three to four times higher in phosphorus relative to
traditional feeds. When nitrogen and phosphorus are fed in excess of
the animal's needs, these nutrients are excreted in the manure. When
manure is applied to crops at rates above their nutrient needs or at
times the crop can not use the nutrients, the nutrients can runoff to
surface waters or leach into ground waters.
Livestock producers can limit the potential pollution from manure
applications to crops by implementing comprehensive nutrient
management. Due to the substantially higher phosphorus content of
manure from livestock fed DGS, producers will potentially need
significantly more acres to apply the manure so that phosphorus will
not be applied at rates above the needs of the crops. This is a
particularly important concern in areas where concentrated livestock
production already produces more phosphorus in the manure than can be
taken up by crops or pasture land in the vicinity.
Several recent studies have indicated that DGS may have an impact
on food safety. Cattle fed DGS have a higher prevalence of a major
food-borne
[[Page 25105]]
pathogen, E. coli O157, than cattle without DGS in their diets.\529\
More research is needed to confirm these studies and devise methods to
eliminate the potential risks.
---------------------------------------------------------------------------
\529\ Jacob, M. D., Fox, J. T., Drouillard, J. S., Renter, D.
G., Nagaraja, T. G., 2008, Effects of dried distillers' grain on
fecal prevalence and growth of Escherichia coli O157 in batch
culture fermentations from cattle, Applied and Environmental
Microbiology, v. 74, no. 1, p. 38-43, available online at: http://aem.asm.org/cgi/content/abstract/74/1/38
---------------------------------------------------------------------------
b. Ethanol Leaks and Spills
The potential for exposure to fuel components and/or additives can
occur when underground fuel storage tanks leak fuel into ground water
that is used for drinking water supplies or when spills occur that
contaminate surface drinking water supplies. Ethanol biodegrades
quickly and is not necessarily the pollutant of greatest concern in
these occurrences. Instead, ethanol's high biodegradability can cause
the plume of BTEX (benzene, toluene, ethylbenzene and xylenes)
compounds in fuel to extend farther (by as much as 70%) \530\ and
persist longer in ground water, thereby increasing potential exposures
to these compounds.
---------------------------------------------------------------------------
\530\ Ruiz-Aguilar, G. M. L.; O'Reilly, K.; Alvarez, P. J. J.,
2003, Forum: A comparison of benzene and toluene plume lengths for
sites contaminated with regular vs. ethanol-amended gasoline, Ground
Water Monitoring and Remediation, v. 23, p. 48-53.
---------------------------------------------------------------------------
With the increasing use of ethanol in the fuel supply nationwide,
it is important to understand the impact of ethanol on the existing
tank infrastructure. Given the corrosivity of ethanol, there is concern
regarding the increased potential for leaks from existing gas stations
and subsequent impacts on drinking water supplies. In 2007, there were
7,500 reported releases from underground storage tanks. Therefore, EPA
is undertaking analyses designed to assess the potential impacts of
ethanol blends on tank infrastructure and leak detection systems and
determine the resulting water quality impacts.
3. Biodiesel Plants
Biodiesel plants use much less water than ethanol plants. Water is
used for washing impurities from the finished product. Water use is
variable, but is usually less than one gallon of water for each gallon
of biodiesel produced. Larger well-designed plants use water more
sparingly, while smaller producers use more water. Some facilities
recycle washwater, which reduces water consumption. The strength of
process wastewater from biodiesel plants is highly variable. Most
production processes produce washwater that has very high BOD levels.
The high strength of these wastes can overload and disrupt municipal
treatment plants.
Crude glycerin is an important side product from the biodiesel
process and is about 10% of the final product. The rapid development of
the biodiesel industry has caused a glut of glycerin production and
many facilities dispose of glycerin. Poor handling of crude glycerin
has resulted in upset of sewage treatment plants and fish kills.
4. Water Quantity
Water demand for crop production for ethanol could potentially be
much larger than biorefinery demand. According to the National Research
Council, the demand for water to irrigate crops for biofuels will not
have an impact on national water use, but it is likely to have
significant local and regional impacts.\531\ The impact is crop and
region specific, but could be especially great in areas where new acres
are irrigated.
---------------------------------------------------------------------------
\531\ Committee on Water Implications of Biofuels Production in
the United States, supra note 2.
---------------------------------------------------------------------------
5. Drinking Water
Increased corn production for ethanol may increase the occurrence
of nitrate, nitrite, and the herbicide atrazine in sources of drinking
water. Under the Safe Drinking Water Act, EPA has established
enforceable standards for these contaminants to protect public health.
Increases in occurrence of these contaminants may raise costs to public
water systems through increased treatment needs or increased pumping
costs where ethanol production is accelerating the long running
depletion of aquifers. There is also a risk of decreased supplies of
drinking water in communities where aquifers are being depleted and
potential contamination due to leaks from gasoline stations using
higher blends of ethanol.
D. Request for Comment on Options for Reducing Water Quality Impacts
EPA is seeking comment on how best to reduce the impacts of
biofuels on water quality. EPA is seeking comment on the use of section
211(c) of the Clean Air Act, as amended by EISA, to address these water
quality issues. Section 211(c) gives the EPA administrator the
discretion to ``control'' the manufacture and sale of a motor vehicle
transportation fuel based on a finding that the fuel, or its emission
product, ``causes or contributes'' to air pollution or water pollution
that may reasonably be anticipated to endanger the public health or
welfare.
In evaluating this option, EPA is seeking comment on whether it
would be appropriate to find that emission products from such
transportation fuels, including renewable fuels, are ``causing or
contributing'' to ``water pollution'' and that this water pollution
``may reasonably be anticipated to endanger the public health or
welfare.'' EPA is also seeking comment on whether it would be allowable
and appropriate to ``control or prohibit the manufacture * * * '' of a
fuel by requiring that manufacturers of such fuels, such as
manufacturers of a biofuel, use, or certify that they used, only corn
feedstocks grown using farming practices designed to reduce nutrient
water pollution. For example, is this a reasonable way to ``offset''
water pollution caused, in part, by air deposition of nitrogen to water
from combustion of transportation fuels with reductions of nitrogen
runoff to water from corn feedstock by means of such ``controls'' on
the manufacture of biofuels adopted pursuant to section 211(c). In the
alternative, would this be a reasonable way to attempt to offset water
pollution caused by the production of the feedstock associated with the
production of the biofuel based on section 211(c).
EPA is seeking comment and suggestions on how biofuel manufacturers
might establish that their biofuel feedstock was grown with appropriate
practices to control nutrient runoff (e.g., require a program similar
to the one used for compliance with the restrictions in the definition
of renewable biomass on previously cleared agricultural land). Finally,
EPA is seeking comments on other approaches, mechanisms, or authorities
that might be adopted in the renewable fuels rule that are likely to
have the effect of reducing the water quality impacts of biofuels.
XI. Public Participation
We request comment on all aspects of this proposal. This section
describes how you can participate in this process.
A. How Do I Submit Comments?
We are opening a formal comment period by publishing this document.
We will accept comments during the period indicated under DATES in the
first part of this proposal. If you have an interest in the proposed
program described in this document, we encourage you to comment on any
aspect of this rulemaking. We also request comment on specific topics
identified throughout this proposal.
Your comments will be most useful if you include appropriate and
detailed
[[Page 25106]]
supporting rationale, data, and analysis. Commenters are especially
encouraged to provide specific suggestions for any changes to any
aspect of the regulations that they believe need to be modified or
improved. You should send all comments, except those containing
proprietary information, to our Air Docket (see ADDRESSES in the first
part of this proposal) before the end of the comment period.
You may submit comments electronically, by mail, or through hand
delivery/courier. To ensure proper receipt by EPA, identify the
appropriate docket identification number in the subject line on the
first page of your comment. Please ensure that your comments are
submitted within the specified comment period. Comments received after
the close of the comment period will be marked ``late.'' EPA is not
required to consider these late comments. If you wish to submit
Confidential Business Information (CBI) or information that is
otherwise protected by statute, please follow the instructions in
Section XI.B.
B. How Should I Submit CBI to the Agency?
Do not submit information that you consider to be CBI
electronically through the electronic public docket,
www.regulations.gov, or by e-mail. Send or deliver information
identified as CBI only to the following address: U.S. Environmental
Protection Agency, Assessment and Standards Division, 2000 Traverwood
Drive, Ann Arbor, MI, 48105, Attention Docket ID EPA-HQ-OAR-2005-0161.
You may claim information that you submit to EPA as CBI by marking any
part or all of that information as CBI (if you submit CBI on disk or
CD-ROM, 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 CBI). Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.
In addition to one complete version of the comments that include
any information claimed as CBI, a copy of the comments that does not
contain the information claimed as CBI must be submitted for inclusion
in the public docket. If you submit the copy that does not contain CBI
on disk orCD-ROM, mark the outside of the disk or CD-ROM clearly that
it does not contain CBI. Information not marked as CBI will be included
in the public docket without prior notice. If you have any questions
about CBI or the procedures for claiming CBI, please consult the person
identified in the FOR FURTHER INFORMATION CONTACT section.
C. Will There Be a Public Hearing?
We will hold a public hearing in Washington DC on June 9, 2009 at
the location shown below. The hearing will start at 10 a.m. local time
and continue until everyone has had a chance to speak.
The Dupont Hotel, 1500 New Hampshire Avenue, NW., Washington, DC
20036, Phone 202-483-6000.
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 in the first part of this proposal at least 8 days
before the hearing. 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 make a tentative schedule for the order of testimony based
on the notifications we receive. This schedule will be available on the
morning of the hearing. In addition, we will reserve a block of time
for anyone else in the audience who wants to give testimony.
We will conduct the hearing informally, and technical rules of
evidence will not apply. We will arrange for a written transcript of
the hearing and keep the official record of the hearing open for 30
days to allow you to submit supplementary information. You may make
arrangements for copies of the transcript directly with the court
reporter.
D. Comment Period
The comment period for this rule will end on July 27, 2009.
E. What Should I Consider as I Prepare My Comments for EPA?
You may find the following suggestions helpful for preparing your
comments:
Explain your views as clearly as possible.
Describe any assumptions that you used.
Provide any technical information and/or data you used
that support your views.
If you estimate potential burden or costs, explain how you
arrived at your estimate.
Provide specific examples to illustrate your concerns.
Offer alternatives.
Make sure to submit your comments by the comment period
deadline identified.
To ensure proper receipt by EPA, identify the appropriate
docket identification number in the subject line on the first page of
your response. It would also be helpful if you provided the name, date,
and Federal Register citation related to your comments.
XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under section 3(f)(1) of Executive Order (EO) 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more. 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.
In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
Draft Regulatory Impact Analysis, which is available in the docket for
this rulemaking and at the docket internet address listed under
ADDRESSES in the first part of this proposal. A more complete
assessment of the costs and benefits associated with this Action will
be completed for the Final Rule.
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 Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by EPA has been
assigned EPA ICR number 2333.01. A draft Supporting Statement has been
placed in the docket for public comment.
The Agency proposes to collect information to ensure compliance
with the provisions in this rule. This includes a variety of
requirements for transportation fuel refiners, blenders, marketers,
distributors, importers, and exporters. The types of information
proposed to be collected includes, but is not limited to:
registrations, periodic compliance reports, product transfer
documentation, transactional information involving RINs and associated
volumes of renewable fuel, and attest engagements. We invite comment on
the proposed collection of information associated with this proposed
rule.
Section 208(a) of the Clean Air Act requires that fuel producers
provide
[[Page 25107]]
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.
As shown in Table XII.B-1, the total annual burden associated with
this proposal is about 323,922 hours and $27,073,827, based on a
projection of 20,216 respondents. The estimated burden for fuel
producers is a total estimate for both new and existing reporting
requirements. Burden means the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
Table XII.B-1--Estimated Burden for Reporting and Recordkeeping Requirements
----------------------------------------------------------------------------------------------------------------
Number of Annual burden Annual costs
Industry sector respondents hours ($)
--------------------------------------------------------------------------------------------------
Fuels:
Producers of renewable fuels...................... 5,472 112,461 8,893,531
Importers of renewable fuels\a\................... 1,131 22,503 1,824,913
Obligated parties, exporters\b\................... 1,410 36,796 2,868,116
RIN owners\c\..................................... 12,083 148,542 13,102,447
Foreign refiners\d\............................... 65 3,460 364,940
Foreign RIN owners................................ 30 135 18,105
Retail stations (pump label)...................... 25 25 1,775
-------------------------------------------------------------
Total......................................... 20,216 323,922 27,073,827
----------------------------------------------------------------------------------------------------------------
\a\ Includes foreign producers.
\b\ Refiners, exporters fall under this category.
\c\ Includes blenders, brokers, marketers, etc. Anyone can own RINs.
\d\ Includes small foreign refiners.
In addition to the estimates shown above, we have separately
estimated the costs of potential third party disclosure that is
associated with the proposed registration requirements explained in
this notice of proposed rulemaking. Potentially affected parties
include farmers, private forest owners, and other biofuel feedstock
producers. We estimate a total of 43,466 respondents, 83,633 annual
burden hours, and $5,937,943 in annual burden cost associated with the
proposed third party disclosure. These estimates are explained in an
addendum to the draft Supporting Statement, which has also been placed
in the public docket.
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 proposed ICR, under Docket ID number EPA-HQ-OAR-2005-
0161. Submit any comments related to the ICR for this proposed rule to
EPA and OMB. See ADDRESSES 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 May 26, 2009, a comment to OMB is best
assured of having its full effect if OMB receives it by June 25, 2009.
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:
----------------------------------------------------------------------------------------------------------------
Industry \a\ Defined as small entity by SBA if: NAICS \a\ codes
----------------------------------------------------------------------------------------------------------------
Gasoline and diesel fuel refiners.. <=1,500 employees........................................ 324110
----------------------------------------------------------------------------------------------------------------
\a\ North American Industrial Classification System.
[[Page 25108]]
2. Background
Section 1501 of the Energy Policy Act of 2005 (EPAct) amended
section 211 of the Clean Air Act (CAA) by adding section 211(o) which
required the Environmental Protection Agency (EPA) to promulgate
regulations implementing a renewable fuel program. EPAct specified that
the regulations must ensure a specific volume of renewable fuel to be
used in gasoline sold in the U.S. each year, with the total volume
increasing over time. The goal of the program was to reduce dependence
on foreign sources of petroleum, increase domestic sources of energy,
and help transition to alternatives to petroleum in the transportation
sector.
The final Renewable Fuels Standard (RFS1) program rule was
published on May 1, 2007, and the program began on September 1, 2007.
Per EPAct, the RFS1 program created a specific annual level for minimum
renewable fuel use that increases over time--resulting in a requirement
that 7.5 billion gallons of renewable fuel be blended into gasoline
(for highway use only) by 2012. Under the RFS1 program, compliance is
based on meeting the required annual renewable fuel volume percent
standard (published annually in the Federal Register by EPA) through
the use of Renewable Identification Numbers, or RINs, 38-digit serial
numbers assigned to each batch of renewable fuel produced. For
obligated parties (those who must meet the annual volume percent
standard), RINs must be acquired to show compliance.
The Energy Independence and Security Act of 2007 (EISA) amended
section 211(o), and the RFS program, by requiring higher volumes of
renewable fuels, to result in 36 billion gallons of renewable fuel by
2022. EISA also expanded the purview of the RFS1 program by requiring
that these renewable fuels be blended into gasoline and diesel fuel
(both highway and nonroad). This expanded the pool of regulated
entities, so the obligated parties under this RFS2 NPRM will now
include certain refiners, importers, and blenders of these fuels that
were not previously covered by the RFS1 program. In addition to the
total renewable fuel standard required by EPAct, EISA added standards
for three additional types of renewable fuels to the program (advanced
biofuel, cellulosic biofuel, and biomass-based diesel) and requires
compliance with all four standards.
Pursuant to section 603 of the RFA, EPA prepared an initial
regulatory flexibility analysis (IRFA) that examines the impact of the
proposed rule on small entities along with regulatory alternatives that
could reduce that impact. The IRFA is available for review in the
docket (in Chapter 7 of the Draft Regulatory Impact Analysis) and is
summarized below.
As required by section 609(b) of the RFA, as amended by SBREFA, EPA
also conducted outreach to small entities and convened a Small Business
Advocacy Review Panel to obtain advice and recommendations of
representatives of the small entities that potentially would be subject
to the rule's requirements.
Consistent with the RFA/SBREFA requirements, the Panel evaluated
the assembled materials and small-entity comments on issues related to
elements of the IRFA. A copy of the Panel Report is included in the
docket for this proposed rule, and a summary of the Panel process, and
subsequent Panel recommendations, is summarized below.
3. Summary of Potentially Affected Small Entities
The small entities that will potentially be subject to the
renewable fuel standard include: Domestic refiners that produce
gasoline and/or diesel and importers of gasoline and/or diesel into the
United States. Based on 2007 data, EPA believes that there are about 95
refiners of gasoline and diesel fuel. Of these, EPA believes that there
are currently 21 refiners producing gasoline and/or diesel fuel that
meet the SBA small entity definition of having 1,500 employees or less.
Further, we believe that three of these refiners own refineries that do
not meet the Congressional ``small refinery'' definition.\532\ It
should be noted that because of the dynamics in the refining industry
(i.e., mergers and acquisitions), the actual number of refiners that
ultimately qualify for small refiner status under the RFS2 program
could be different than this initial estimate.
---------------------------------------------------------------------------
\532\ EPAct defined a ``small refinery'' as a refinery with a
crude throughput of no more than 75,000 barrels of crude per day (at
CAA section 211(o)(1)(K)). This definition is based on facility size
and is different than SBA's small refiner definition (which is based
on company size). A small refinery could be owned by a larger
refiner that exceeds SBA's small entity standards. SBA's size
standards were established to set apart those businesses which are
most likely to be at an inherent economic disadvantage relative to
larger businesses.
---------------------------------------------------------------------------
4. Potential Reporting, Recordkeeping, and Compliance
For any fuel control program, EPA must have assurance that any fuel
produced meets all applicable standards and requirements, and that the
fuel continues to meet those standards and requirements as it passes
downstream through the distribution system to the ultimate end user.
Registration, reporting, and recordkeeping are necessary to track
compliance with the RFS2 requirements and transactions involving RINs.
As discussed above in Sections III.J and IV.E, the proposed compliance
requirements under the RFS2 program are in many ways similar to those
required under the RFS1 program, with some modifications to account for
the new requirements of EISA.
5. Related Federal Rules
We are aware of a few other current or proposed Federal rules that
are related to the upcoming proposed rule. The primary federal rules
that are related to the proposed RFS2 rule under consideration are the
first Renewable Fuel Standard (RFS1) rule (72 FR 23900, May 1, 2007)
and the RFS1 Technical Amendment Direct Final Rulemaking (73 FR 57248,
October 2, 2008).\533\
---------------------------------------------------------------------------
\533\ This Direct Final Rule corrects minor typographical errors
and provides clarification on existing provisions in the RFS1
regulations.
---------------------------------------------------------------------------
6. Summary of SBREFA Panel Process and Panel Outreach
a. Significant Panel Findings
The Small Business Advocacy Review Panel (SBAR Panel, or the Panel)
considered regulatory options and flexibilities to help mitigate
potential adverse effects on small businesses as a result of this rule.
During the SBREFA Panel process, the Panel sought out and received
comments on the regulatory options and flexibilities that were
presented to SERs and Panel members. The recommendations of the Panel
are described below and are also located in Section 9 of the SBREFA
Final Panel Report, which is available in the public docket.
b. Panel Process
As required by section 609(b) of the RFA, as amended by SBREFA, we
also conducted outreach to small entities and convened an SBAR Panel to
obtain advice and recommendations of representatives of the small
entities that potentially would be subject to the rule's requirements.
On July 9, 2008, EPA's Small Business Advocacy Chairperson convened a
Panel under Section 609(b) of the RFA. In addition to the Chair, the
Panel consisted of the Division Director of the Assessment and
Standards Division of EPA's Office of Transportation and Air Quality,
the Chief Counsel for Advocacy of the Small Business Administration,
and the
[[Page 25109]]
Administrator of the Office of Information and Regulatory Affairs
within the Office of Management and Budget. As part of the SBAR Panel
process, we conducted outreach with representatives from
representatives of small businesses that would potentially be affected
by the proposed rulemaking. We met with these Small Entity
Representatives (SERs) to discuss the potential rulemaking approaches
and potential options to decrease the impact of the rulemaking on their
industries. We distributed outreach materials to the SERs; these
materials included background on the rulemaking, possible regulatory
approaches, and possible rulemaking alternatives. The Panel met with
SERs from the industries that would be directly affected by the RFS2
rule on July 30, 2008 to discuss the outreach materials and receive
feedback on the approaches and alternatives detailed in the outreach
packet (the Panel also met with SERs on June 3, 2008 for an initial
outreach meeting). The Panel received written comments from the SERs
following the meeting in response to discussions had at the meeting and
the questions posed to the SERs by the Agency. The SERs were
specifically asked to provide comment on regulatory alternatives that
could help to minimize the rule's impact on small businesses.
In general, SERs stated that they believed that small refiners
would face challenges in meeting the new standards. More specifically,
they voiced concerns with respect to the RIN program itself,
uncertainty (with the required renewable fuel volumes, RIN
availability, and cost), and the desire for a RIN system review.
The Panel's findings and discussions were based on the information
that was available during the term of the Panel and issues that were
raised by the SERs during the outreach meetings and in their comments.
One concern that was raised by EPA with regard to provisions for small
refiners in the RFS2 rule is that this rule presents a very different
issue than the small refinery versus small refiner concept from RFS1.
This issue deals with whether EPA has the authority to provide small
refineries that are operated by a small refiner with an extension of
time that would be different from (and more than) the temporary
exemption specified by Congress in section 211(o)(9) for small
refineries. For those small refiners who are covered by the small
refinery provisions, Congress has specifically adopted a relief
provision aimed at their refineries. This provides a temporary
extension through December 31, 2010 and allows for further extensions
only if certain criteria are met. EPA believes that providing small
refineries (and thus, small refiners who own small refineries) with an
additional exemption different from that provided by section 211(o)(9)
raises concerns about inconsistency with the intent of Congress.
Congress spoke directly to the relief that EPA may provide for small
refineries, including those small refineries operated by small
refiners, and limited it to a blanket exemption through December 31,
2010, with additional extensions if the criteria specified by Congress
were met. An additional or different extension, relying on a more
general provision in section 211(o)(3), would raise questions about
consistency with the intent of Congress.
It was agreed that EPA should consider the issues raised by the
SERs and discussions had by the Panel itself, and that EPA should
consider comments on flexibility alternatives that would help to
mitigate negative impacts on small businesses to the extent legally
allowable by the Clean Air Act. Alternatives discussed throughout the
Panel process included those offered in previous or current EPA
rulemakings, as well as alternatives suggested by SERs and Panel
members. A summary of these recommendations is detailed below, and a
full discussion of the regulatory alternatives and hardship provisions
discussed and recommended by the Panel can be found in the SBREFA Final
Panel Report. A complete discussion of the provisions for which we are
requesting comment and/or proposing in this action can be found in
Section IV.B of this preamble. Also, the Panel Report includes all
comments received from SERs (Appendix B of the Report) and summaries of
the two outreach meetings that were held with the SERs. In accordance
with the RFA/SBREFA requirements, the Panel evaluated the
aforementioned materials and SER comments on issues related to the
IRFA. The Panel's recommendations from the Final Panel Report are
discussed below.
c. Panel Recommendations
The purpose of the Panel process is to solicit information as well
as suggested flexibility options from the SERs, and the Panel
recommended that EPA continue to do so during the development of the
RFS2 rule. Recognizing the concerns about EPA's authority to provide
extensions to a subset of small refineries (i.e., those that are owned
by small refiners) different from that provided to small refineries in
section 211(o)(9), the Panel recommended that EPA continue to evaluate
this issue, and that EPA request comment on its authority and the
appropriateness of providing extensions beyond those authorized by
section 211(o)(9) for small refineries operated by a small refiner. The
Panel also recommended that EPA propose to provide the same extension
provision of 211(o)(9) to small refiners who do not own small
refineries as is provided for small refiners who do own small
refineries.
i. Delay in Standards
The RFS1 program regulations provide small refiners who operate
small refineries as well as small refiners who do not operate small
refineries with a temporary exemption from the standard through
December 31, 2010. Small refiner SERs suggested that an additional
temporary exemption for the RFS2 program would be beneficial to them in
meeting the standards. EPA evaluated a temporary exemption for at least
some of the four required RFS2 standards for small refiners. The Panel
recommended that EPA propose a delay in the effective date of the
standards until 2014 for small entities, to the maximum extent allowed
by the statute. However, the Panel recognized that EPA has serious
concerns about its authority to provide an extension of the temporary
exemption for small refineries that is different from that provided in
CAA section 211(o)(9), since Congress specifically addressed an
extension for small refineries in that provision.
The Panel did recommend that EPA propose other avenues through
which small refineries and small refiners could receive extensions of
the temporary exemption. These avenues, as discussed in greater detail
in Sections XII.C.6.c.v and vi below, are a possible extension of the
temporary exemption for an additional two years following a study of
small refineries by the Department of Energy (DOE) and provisions for
case-by-case economic hardship relief.
ii. Phase-in
Small refiner SERs' suggested that a phase-in of the obligations
applicable to small refiners would be beneficial for compliance, such
that small refiners would comply by gradually meeting the standards on
an incremental basis over a period of time, after which point they
would comply fully with the RFS2 standards, EPA has serious concerns
about its authority to allow for such a phase-in of the standards. CAA
section 211(o)(3)(B) states that the renewable fuel obligation shall
``consist of a single applicable percentage that applies to all
categories of persons specified'' as obligated parties. This kind of
phase-in
[[Page 25110]]
approach would result in different applicable percentages being applied
to different obligated parties. Further, as discussed above, such a
phase-in approach would provide more relief to small refineries
operated by small refiners than that provided under the small refinery
provision. Thus the Panel recommended that EPA should invite comment on
a phase-in, but not propose such a provision.
iii. RIN-Related Flexibilities
The small refiner SERs requested that the proposed rule contain
provisions for small refiners related to the RIN system, such as
flexibilities in the RIN rollover cap percentage and allowing all small
refiners to use RINs interchangeably. Currently in the RFS1 program,
EPA allows for 20% of a previous year's RINs to be ``rolled over'' and
used for compliance in the following year. A provision to allow for
flexibilities in the rollover cap could include a higher RIN rollover
cap for small refiners for some period of time or for at least some of
the four standards. Since the concept of a rollover cap was not
mandated by section 211(o), EPA believes that there may be an
opportunity to provide appropriate flexibility in this area to small
refiners under the RFS2 program but only if it is determined in the DOE
small refinery study that there is a disproportionate effect warranting
relief. The Panel recommended that EPA request comment on increasing
the RIN rollover cap percentage for small refiners, and further that
EPA should request comment on an appropriate level of that percentage.
The Panel recommended that EPA invite comment on allowing RINs to
be used interchangeably for small refiners, but not propose this
concept because under this approach small refiners would arguably be
subject to a different applicable percentage than other obligated
parties. This concept would also fail to require the four different
standards mandated by Congress (e.g., conventional biofuel could not be
used instead of cellulosic biofuel or biomass-based diesel).
iv. Program Review
With regard to the suggested program review, EPA raised the concern
that this could lead to some redundancy since EPA is required to
publish a notice of the applicable RFS standards in the Federal
Register annually, and that this annual process will inevitably include
an evaluation of the projected availability of renewable fuels.
Nevertheless, the SBA and OMB Panel members stated that they believe
that a program review could be helpful to small entities in providing
them some insight to the RFS program's progress and alleviate some
uncertainty regarding the RIN system. As EPA will be publishing a
Federal Register notice annually, the Panel recommended that EPA
include an update of RIN system progress (e.g., RIN trading, RIN
availability, etc.) in this notice and that the results of this
evaluation be considered in any request for case-by-case hardship
relief.
v. Extensions of the Temporary Exemption Based on a Study of Small
Refinery Impacts
The Panel recommended that EPA propose in the RFS2 program the
provision at 40 CFR 80.1141(e) extending the RFS1 temporary exemption
for at least two years for any small refinery that DOE determines would
be subject to disproportionate economic hardship if required to comply
with the RFS2 requirements.
Section 211(o)(9)(A)(ii) required that by December 31, 2008, DOE
was to perform a study of the economic impacts of the RFS requirements
on small refineries to assess and determine whether the RFS
requirements would impose a disproportionate economic hardship on small
refineries, and submit this study to EPA. Section 211(o)(9) also
provided that small refineries found to be in a disproportionate
economic hardship situation would receive an extension of the temporary
exemption for at least two years.
The Panel also recommended that EPA work with DOE in the
development of the small refinery study, specifically to communicate
the comments that SERs raised during the Panel process.
vi. Extensions of the Temporary Exemption Based on Disproportionate
Economic Hardship
While SERs did not specifically comment on the concept of hardship
provisions for the upcoming proposal, the Panel noted that under CAA
section 211(o)(9)(B) small refineries may petition EPA for case-by-case
extensions of the small refinery temporary exemption on the basis of
disproportionate economic hardship. Refiners may petition EPA for this
case-by-case hardship relief at any time.
The Panel recommended that EPA propose in the RFS2 program a case-
by-case hardship provision for small refineries similar to that
provided at 40 CFR 80.1141(e)(1). The Panel also recommended that EPA
propose a case-by-case hardship provision for small refiners that do
not operate small refineries that is comparable to that provided for
small refineries under section 211(o)(9)(B), using its discretion under
CAA section 211(o)(3)(B). This would apply if EPA does not adopt an
automatic extension for small refiners, and would allow those small
refiners that do not operate small refineries to apply for the same
kind of extension as a small refinery. The Panel recommended that EPA
take into consideration the results of the annual update of RIN system
progress and the DOE small refinery study in assessing such hardship
applications.
We invite comments on all aspects of the proposal and its impacts
on small entities.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L.
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.
Today's proposal contains no Federal mandates (under the regulatory
provisions of Title II of the UMRA) for
[[Page 25111]]
State, local, or tribal governments. The rule imposes no enforceable
duty on any State, local or tribal governments. EPA has determined that
this rule contains no regulatory requirements that might significantly
or uniquely affect small governments. EPA has determined that this
proposal contains a Federal mandate that may result in expenditures of
$100 million or more for the private sector in any one year. EPA
believes that the proposal represents the least costly, most cost-
effective approach to achieve the statutory requirements of the rule.
The costs and benefits associated with the proposal are discussed above
and in the Draft Regulatory Impact Analysis, as required by the UMRA.
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 will be implemented at the Federal
level and impose compliance costs only on transportation fuel refiners,
blenders, marketers, distributors, importers, and exporters. Tribal
governments would 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 Risks and Safety Risks
EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
only to those regulatory actions that concern health or safety risks,
such that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This action is not subject to EO
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks and because it implements specific
standards established by Congress in statutes.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355
(May 22, 2001)) because it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy. In fact, this
rule has a positive effect on energy supply and use. By promoting the
diversification of transportation fuels, this rule enhances energy
supply. Therefore, we have concluded that this rule is not likely to
have any adverse energy effects. Our energy effects analysis is
described above in Section IX.
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law No. 104-113, 12(d) (15 U.S.C. 272
note) 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. NTTAA directs EPA to
provide Congress, through OMB, explanations when the Agency decides not
to use available and applicable voluntary consensus standards.
This rulemaking proposes changes to the Renewable Fuel Standard
(RFS) program at Title 40 of the Code of Federal Regulations, Subpart K
which already contains voluntary consensus standard ASTM D6751-06a
``Standard Specification for Biodiesel Fuel Blend Stock (B100) for
Middle Distillate Fuels''. This standard was developed by ASTM
International (originally known as the American Society for Testing and
Materials), Subcommittee D02.E0, and was approved in August 2006. The
standard may be obtained through the ASTM Web site (www.astm.org) or by
calling ASTM at (610) 832-9585.
This proposed rulemaking does not propose to change this voluntary
consensus standard, and does not involve any other technical standards.
Therefore, EPA is not considering the use of any voluntary consensus
standards other than that described above.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States. EPA lacks the discretionary authority
to address environmental justice in this proposed rulemaking since the
Agency is implementing specific standards established by Congress in
statutes. Although EPA lacks authority to modify today's regulatory
decision on the basis of environmental justice considerations, EPA
nevertheless determined that this proposed rule does not have a
disproportionately high and adverse human health or environmental
impact on minority or low-income populations.
XIII. Statutory Authority
Statutory authority for this action comes from 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,
[[Page 25112]]
208, and 301(a) of the Clean Air Act, 42 U.S.C. 7414, 7542, and
7601(a).
List of Subjects in 40 CFR Part 80
Environmental protection, Air pollution control, Diesel fuel, Fuel
additives, Gasoline, Imports, Incorporation by reference, Labeling,
Motor vehicle pollution, Penalties, Reporting and recordkeeping
requirements.
Dated: May 5, 2009.
Lisa P. Jackson,
Administrator.
For the reasons set forth in the preamble, 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. A new Subpart M is added to part 80 to read as follows:
Subpart M--Renewable Fuel Standard
Sec.
80.1400 Applicability.
80.1401 Definitions.
80.1402 [Reserved]
80.1403 Which fuels are not subject to the 20% GHG thresholds?
80.1404 [Reserved]
80.1405 What are the Renewable Fuel Standards?
80.1406 To whom do the Renewable Volume Obligations apply?
80.1407 How are the Renewable Volume Obligations calculated?
80.1408-80.1414 [Reserved]
80.1415 How are equivalence values assigned to renewable fuel?
80.1416 Treatment of parties who produce or import new renewable
fuels and pathways.
80.1417-80.1424 [Reserved]
80.1425 Renewable Identification Numbers (RINs).
80.1426 How are RINs generated and assigned to batches of renewable
fuel by renewable fuel producers or importers?
80.1427 How are RINs used to demonstrate compliance?
80.1428 General requirements for RIN distribution.
80.1429 Requirements for separating RINs from volumes of renewable
fuel.
80.1430 Requirements for exporters of renewable fuels.
80.1431 Treatment of invalid RINs.
80.1432 Reported spillage or disposal of renewable fuel.
80.1433-80.1439 [Reserved]
80.1440 What are the provisions for blenders who handle and blend
less than 125,000 gallons of renewable fuel per year?
80.1441 Small refinery exemption.
80.1442 What are the provisions for small refiners under the RFS
program?
80.1443 What are the opt-in provisions for noncontiguous states and
territories?
80.1444-80.1448 [Reserved]
80.1449 What are the Production Outlook Report requirements?
80.1450 What are the registration requirements under the RFS
program?
80.1451 What are the recordkeeping requirements under the RFS
program?
80.1452 What are the reporting requirements under the RFS program?
80.1453 What are the product transfer document (PTD) requirements
for the RFS program?
80.1454 What are the provisions for renewable fuel production
facilities and importers who produce or import less than 10,000
gallons of renewable fuel per year?
80.1455 What are the provisions for cellulosic biofuel allowances?
80.1456-80.1459 [Reserved]
80.1460 What acts are prohibited under the RFS program?
80.1461 Who is liable for violations under the RFS program?
80.1462 [Reserved]
80.1463 What penalties apply under the RFS program?
80.1464 What are the attest engagement requirements under the RFS
program?
80.1465 What are the additional requirements under this subpart for
foreign small refiners, foreign small refineries, and importers of
RFS-FRFUEL?
80.1466 What are the additional requirements under this subpart for
foreign producers and importers of renewable fuels?
80.1467 What are the additional requirements under this subpart for
a foreign RIN owner?
80.1468 [Reserved]
80.1469 What are the labeling requirements that apply to retailers
and wholesale purchaser-consumers of ethanol fuel blends that
contain greater than 10 volume percent ethanol?
Subpart M--Renewable Fuel Standard
Sec. 80.1400 Applicability.
The provisions of this Subpart M shall apply for all renewable fuel
produced on or after January 1, 2010, for all RINs generated after
January 1, 2010, and for all renewable volume obligations and
compliance periods starting with January 1, 2010. Except as provided
otherwise in this Subpart M, the provisions of Subpart K of this Part
80 shall not apply for such renewable fuel, RINs, renewable volume
obligations, or compliance periods.
Sec. 80.1401 Definitions.
The definitions of Sec. 80.2 and of this section apply for the
purposes of this subpart M. The definitions of this section do not
apply to other subparts unless otherwise noted. Note that many terms
defined here are common terms that have specific meanings under this
subpart M (such as the terms ``co-processed,'' ``cropland,'' and ``yard
waste''). The definitions follow:
Actual peak capacity means the maximum annual volume of renewable
fuels produced from a specific renewable fuel production facility on an
annual basis.
(1) For facilities that commenced construction prior to December
19, 2007 the maximum annual volume is for any year prior to 2008.
(2) For facilities that commenced construction after December 19,
2007, and are fired with natural gas, biomass, or a combination
thereof, the maximum annual volume may be for any year after startup
over the first three years of operation.
Advanced biofuel means renewable fuel, other than ethanol derived
from cornstarch, that qualifies for a D code of 3 pursuant to Sec.
80.1426(d).
Areas at risk of wildfire are areas located within, or within one
mile of, forestland, tree plantation, or any other generally
undeveloped tract of land that is at least one acre in size with
substantial vegetative cover.
Baseline volume means the greater of nameplate capacity or actual
peak capacity of a specific renewable fuel production facility.
(1) For facilities that commenced construction on or before
December 19, 2007, the actual peak capacity may be for any year prior
to 2008.
(2) For facilities that commenced construction after December 19,
2007, and are fired with natural gas, biomass, or a combination
thereof, the actual peak capacity may be for any year after startup for
the facility over the first three years of operation.
Biomass-based diesel means a renewable fuel which meets the
requirements in paragraph (1) or (2) of this definition:
(1) A transportation fuel or fuel additive which is all of the
following:
(i) Registered as a motor vehicle fuel or fuel additive under 40
CFR part 79.
(ii) A mono-alkyl ester and meets ASTM D-6751-07, entitled
``Standard Specification for Biodiesel Fuel Blendstock (B100) for
Middle Distillate Fuels.'' ASTM D-6751-07 is incorporated by reference.
This incorporation by reference was approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR Part 51.
A copy may be obtained from the American Society for Testing and
Materials, 100 Barr Harbor Drive, West Conshohocken, Pennsylvania. A
copy may be inspected at the EPA Docket Center, Docket No. EPA-HQ-OAR-
2005-0161, EPA/DC, EPA West, Room 3334, 1301
[[Page 25113]]
Constitution Ave., NW., Washington, DC, or at the National Archives and
Records Administration (NARA). For information on the availability of
this material at NARA, call 866-272-6272, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html.
(iii) Intended for use in engines that are designed to run on
conventional diesel fuel.
(iv) Qualifies for a D code of 2 pursuant to Sec. 80.1426(d).
(2) A non-ester renewable diesel.
(3) Renewable fuel that is co-processed is not biomass-based
diesel.
Carbon Capture and Storage (CCS) is the process of capturing carbon
dioxide from an emission source, (typically) converting it to a
supercritical state, transporting it to an injection site, and
injecting it into deep subsurface rock formations for long-term
storage.
Cellulosic biofuel means renewable fuel derived from any cellulose,
hemi-cellulose, or lignin that is derived from renewable biomass and
that qualifies for a D code of 1 pursuant to Sec. 80.1426(d).
Combined heat and power (CHP), also known as cogeneration, refers
to industrial processes in which byproduct heat that would otherwise be
released into the environment is used for process heating and/or
electricity production.
Commence construction, as applied to facilities that produce
renewable fuel, means that the owner or operator has all necessary
preconstruction approvals or permits (as defined at 40 CFR
52.21(a)(10)), that for multi-phased projects, the commencement of
construction of one phase does not constitute commencement of
construction of any later phase, unless each phase is mutually
dependent for physical and chemical reasons only, and has satisfied
either of the following:
(1) Begun, or caused to begin, a continuous program of actual
construction on-site (as defined in 40 CFR 52.21(a)(11)) of the
facility to be completed within a reasonable time.
(2) Entered into binding agreements or contractual obligations,
which cannot be cancelled or modified without substantial loss to the
owner or operator, to undertake a program of actual construction of the
facility to be completed within a reasonable time.
Co-processed means that renewable biomass was simultaneously
processed with petroleum feedstock in the same unit or units to produce
a fuel that is partially renewable.
Crop residue is the residue left over from the harvesting of
planted crops.
Cropland is land used for production of crops for harvest and
includes cultivated cropland, such as for row crops or close-grown
crops, and non-cultivated cropland, such as for horticultural crops.
Diesel refers to any and all of the products specified at Sec.
80.1407(f).
Ecologically sensitive forestland means forestland that is:
(1) An ecological community listed in a document entitled ``Listing
of Forest Ecological Communities Pursuant to 40 CFR 80.1401,''
(available in public docket EPA-HQ-OAR-2005-0161); or
(2) Old growth or late successional, characterized by trees at
least 200 years in age.
Existing agricultural land is cropland, pastureland, or land
enrolled in the Conservation Reserve Program (administered by the U.S.
Department of Agriculture's Farm Service Agency) that was cleared or
cultivated prior to December 19, 2007, and that, since December 19,
2007, has been continuously:
(1) Nonforested; and
(2) Actively managed as agricultural land or fallow, as evidenced
by any of the following:
(i) Records of sales of planted crops, crop residue, or livestock,
or records of purchases for land treatments such as fertilizer, weed
control, or reseeding.
(ii) A written management plan for agricultural purposes.
(iii) Documented participation in an agricultural management
program administered by a Federal, state, or local government agency.
(iv) Documented management in accordance with a certification
program for agricultural products.
Export of renewable fuel means:
(1) Transfer of any renewable fuel to a location outside the
contiguous 48 states and Hawaii; and
(2) Transfer of any renewable fuel from a location in the
contiguous 48 states to Alaska 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. 80.1443.
Facility means all of the activities and equipment associated with
the production of renewable fuel starting from the point of delivery of
feedstock material to the point of final storage of the end product,
which are located on one property, and are under the control of the
same party (or parties under common control).
Fallow means cropland, pastureland, or land enrolled in the
Conservation Reserve Program (administered by the U.S. Department of
Agriculture's Farm Service Agency) that is intentionally left idle to
regenerate for future agricultural purposes with no seeding or
planting, harvesting, mowing, or treatment during the fallow period.
Forestland is generally undeveloped land covering a minimum area of
1 acre upon which the primary vegetative species are trees, including
land that formerly had such tree cover and that will be regenerated.
Forestland does not include tree plantations.
Gasoline refers to any and all of the products specified at Sec.
80.1407(c).
Importers. An importer of transportation fuel or renewable fuel is:
(1) Any party who brings transportation fuel or renewable fuel into
the 48 contiguous states of the United States and Hawaii, from a
foreign country or from an area that has not opted in to the program
requirements of this subpart pursuant to Sec. 80.1443; and
(2) Any party who brings transportation fuel or renewable fuel into
an area that has opted in to the program requirements of this subpart
pursuant to Sec. 80.1443.
Motor vehicle has the meaning given in Section 216(2) of the Clean
Air Act (42 U.S.C. 7550(2)).
Nameplate capacity means:
(1) The maximum rated annual volume output of renewable fuel
produced by a renewable fuel production facility under specific
conditions as indicated in applicable air permits issued by the U.S.
Environmental Protection Agency, state, or local air pollution control
agencies and that govern the construction and/or operation of the
renewable fuel facility.
(2) If the maximum rated annual volume output of renewable fuel is
not specified in any applicable air permits issued by the U.S.
Environmental Protection Agency, state, or local air pollution control
agencies, then nameplate capacity is the actual peak capacity of the
facility.
Neat renewable fuel is a renewable fuel to which only a de minimis
amount of gasoline (as defined in Section 211(k)(10)(F) of the Clean
Air Act (42 U.S.C. 7550)) or diesel fuel has been added.
Non-ester renewable diesel means renewable fuel which is all the
following:
(1) Registered as a motor vehicle fuel or fuel additive under 40
CFR Part 79.
(2) Not a mono-alkyl ester.
(3) Intended for use in engines that are designed to run on
conventional diesel fuel.
(4) Derived from nonpetroleum renewable resources.
(5) Qualifies for a D code of 3 as defined in Sec. 80.1426(d).
Nonforested land means land that is not forestland.
Nonpetroleum renewable resources include, but are not limited to
the following:
[[Page 25114]]
(1) Plant oils.
(2) Animal fats and animal wastes, including poultry fats and
poultry wastes, and other waste materials.
Nonroad vehicle has the meaning given in Section 216(11) of the
Clean Air Act (42 U.S.C. 7550(11)).
Ocean-going vessel means, for this subpart only, a vessel propelled
by a Category 3 (C3) (as defined in 40 CFR 1042.901) marine engine that
uses residual fuel (as defined at Sec. 80.2(bbb)) or operates
internationally. Note that ocean-going vessels may also include smaller
engines such as Category 2 auxiliary engines.
Pastureland is land managed for the production of indigenous or
introduced forage plants for livestock grazing or hay production, and
to prevent succession to other plant types.
Planted crops are all annual or perennial agricultural crops that
may be used as feedstocks for renewable fuel, such as grains, oilseeds,
sugarcane, switchgrass, prairie grass, and other species providing that
they were intentionally applied to the ground by humans either by
direct application as seed or nursery stock, or through intentional
natural seeding by mature plants left undisturbed for that purpose.
Planted trees are trees planted by humans from nursery stock or by
seed either through direct application to the ground or by intentional
natural seeding by mature trees left undisturbed for that purpose.
Pre-commercial thinnings are trees, including unhealthy or diseased
trees, primarily removed to reduce stocking to concentrate growth on
more desirable, healthy trees.
Renewable biomass means each of the following:
(1) Planted crops and crop residue harvested from existing
agricultural land.
(2) Planted trees and slash from a tree plantation located on non-
federal land (including land belonging to an Indian tribe or an Indian
individual that is held in trust by the U.S. or subject to a
restriction against alienation imposed by the U.S.) that was cleared at
any time prior to December 19, 2007, and has been continuously actively
managed since December 19, 2007. Active management is evidenced by any
of the following:
(i) Records of sales of planted trees or slash, or records of
purchases of seeds, seedlings, or other nursery stock.
(ii) A written management plan for silvicultural purposes.
(iii) Documented participation in a silvicultural program
administered by a Federal, state, or local government agency.
(iv) Documented management in accordance with a certification
program for silvicultural products.
(3) Animal waste material and animal byproducts.
(4) Slash and pre-commercial thinnings from non-federal forestland
(including forestland belonging to an Indian tribe or an Indian
individual, that are held in trust by the United States or subject to a
restriction against alienation imposed by the United States) that is
not ecologically sensitive forestland.
(5) Biomass (organic matter that is available on a renewable or
recurring basis) obtained from within 200 feet of buildings,
campgrounds, and other areas regularly occupied by people, or of public
infrastructure, such as utility corridors, bridges, and roadways, in
areas at risk of wildfire.
(6) Algae.
(7) Separated yard waste or food waste, including recycled cooking
and trap grease.
Renewable fuel means a fuel which meets all of the following:
(1) Fuel that is produced from renewable biomass.
(2) Fuel that is used to replace or reduce the quantity of fossil
fuel present in a transportation fuel, home heating oil, or jet fuel.
(3) Ethanol covered by this definition shall be denatured as
required and defined in 27 CFR parts 19 through 21. Any volume of
denaturant added to the undenatured ethanol by a producer or importer
in excess of 5 volume percent shall not be included in the volume of
ethanol for purposes of determining compliance with the requirements
under this subpart.
Renewable Identification Number (RIN), is a unique number generated
to represent a volume of renewable fuel pursuant to Sec. Sec. 80.1425
and 80.1426.
(1) Gallon-RIN is a RIN that represents an individual gallon of
renewable fuel; and
(2) Batch-RIN is a RIN that represents multiple gallon-RINs.
Slash is the residue, including treetops, branches, and bark, left
on the ground after logging or accumulating as a result of a storm,
fire, delimbing, or other similar disturbance.
Small refinery means a refinery for which the average aggregate
daily crude oil throughput for calendar year 2006 (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.
Transportation fuel means fuel for use in motor vehicles, motor
vehicle engines, nonroad vehicles, or nonroad engines (except for
ocean-going vessels).
Tree plantation is a stand of no fewer than 100 planted trees of
similar age comprising one or two tree species or an area managed for
growth of such trees covering a minimum of 1 acre.
Yard waste is leaves, sticks, pine needles, grass and hedge
clippings, and similar waste from residential, commercial, or
industrial areas.
Sec. 80.1402 [Reserved]
Sec. 80.1403 Which fuels are not subject to the 20% GHG thresholds?
(a) Pursuant to the definition of baseline volume in Sec. 80.1401,
the baseline volume of renewable fuel that is produced from facilities
which commenced construction on or before December 19, 2007, shall not
be subject to the 20 percent reduction in GHG emissions and shall be
deemed grandfathered for purposes of generating RINs pursuant to Sec.
80.1426(d)(7)(ii) if the owner or operator:
(1) Did not discontinue construction for a period of 18 months or
more after December 19, 2007; and
(2) Completed construction within 36 months of December 19, 2007.
(b) The volume of ethanol that is produced from facilities which
commenced construction after December 19, 2007 and on or before
December 31, 2009, shall not be subject to the 20 percent reduction in
GHG emissions and shall be deemed grandfathered for purposes of
generating RINs pursuant to Sec. 80.1426(d)(7)(ii) only if such
facilities are fired with natural gas, biomass, or a combination
thereof.
(c) The annual volume of renewable fuel during a calendar year from
facilities described in paragraph (a) of this section that is beyond
the baseline volume shall be subject to the 20 percent reduction in GHG
emissions and such volume shall not be deemed grandfathered for
purposes of generating RINs pursuant to Sec. 80.1426(d)(7)(ii).
(d) For those facilities described in paragraph (a) of this section
which produce ethanol and are fired with natural gas, biomass, or a
combination thereof, increases in the annual volume of ethanol above
the baseline volume during a calendar year shall not be subject to the
20 percent reduction in GHG emissions and shall be deemed grandfathered
for purposes of generating RINs pursuant to Sec. 80.1426(d)(7)(ii),
provided that:
(1) The facility continues to be fired only with natural gas,
biomass, or a combination thereof; and
(2) If the increases in volume at the facility are due to new
construction, such new construction must have commenced on or before
December 31, 2009.
[[Page 25115]]
(e) If there are any changes in the mix of renewable fuels produced
by those facilities described in paragraph (d) of this section, only
the ethanol volume will not be subject to the 20 percent reduction in
GHG emissions and shall be deemed grandfathered for purposes of
generating RINs pursuant to Sec. 80.1426(d)(7)(ii).
Sec. 80.1404 [Reserved]
Sec. 80.1405 What are the Renewable Fuel Standards?
(a) Renewable Fuel Standards for 2010. (1) The value of the
cellulosic biofuel standard for 2010 shall be 0.06 percent.
(2) The value of the biomass-based diesel standard for 2010 shall
be 0.71 percent.
(3) The value of the advanced biofuel standard for 2010 shall be
0.59 percent.
(4) The value of the renewable fuel standard for 2010 shall be 8.01
percent.
(b) Beginning with the 2011 compliance period, EPA will calculate
the value of the annual standards and publish these values in the
Federal Register by November 30 of the year preceding the compliance
period.
(c) EPA will base the calculation of the standards on information
provided by the Energy Information Administration regarding projected
gasoline and diesel volumes and projected volumes of renewable fuels
expected to be used in gasoline and diesel blending for the upcoming
year.
(d) EPA will calculate the annual renewable fuel standards using
the following equations:
[GRAPHIC] [TIFF OMITTED] TP26MY09.012
[GRAPHIC] [TIFF OMITTED] TP26MY09.013
[GRAPHIC] [TIFF OMITTED] TP26MY09.014
[GRAPHIC] [TIFF OMITTED] TP26MY09.015
Where:
StdCB,i = The cellulosic biofuel standard for year i, in
percent.
StdBBD,i = The biomass-based diesel standard for year i,
in percent.
StdAB,i = The advanced biofuel standard for year i, in
percent.
StdRF,i = The renewable fuel standard for year i, in
percent.
RFVCB,i = Annual volume of cellulosic biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons.
RFVBBD,i = Annual volume of biomass-based diesel required
by section 211(o)(2)(B) of the Clean Air Act for year i, in gallons.
RFVAB,i = Annual volume of advanced biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons.
RFVRF,i = Annual volume of renewable fuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons.
Di = Amount of diesel projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons.
RGi = Amount of renewable fuel blended into gasoline that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons.
RDi = Amount of renewable fuel blended into diesel that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons.
GSi = Amount of gasoline projected to be used in Alaska
or a U.S. territory, in year i, if the state or territory has opted-
in or opts-in, in gallons.
RGSi = Amount of renewable fuel blended into gasoline
that is projected to be consumed in Alaska or a U.S. territory, in
year i, if the state or territory opts-in, in gallons.
DSi = Amount of diesel projected to be used in Alaska or
a U.S. territory, in year i, if the state or territory has opted-in
or opts-in, in gallons.
RDSi = Amount of renewable fuel blended into diesel that
is projected to be consumed in Alaska or a U.S. territory, in year
i, if the state or territory opts-in, in gallons.
GEi = The amount of gasoline projected to be produced by
exempt small refineries and small refiners, in year i, in gallons in
any year they are exempt per Sec. Sec. 80.1441 and 80.1442,
respectively. Assumed to equal 0.119 * (Gi-
RGi).
DEi = The amount of diesel fuel projected to be produced
by exempt small refineries and small refiners in year i, in gallons,
in any year they are exempt per Sec. Sec. 80.1441 and 80.1442,
respectively. Assumed to equal 0.152 * (Di-
RDi).
Sec. 80.1406 To whom do the Renewable Volume Obligations apply?
(a)(1) An obligated party is any refiner that produces gasoline or
diesel fuel within the 48 contiguous states or Hawaii, or any importer
that imports gasoline or diesel fuel into the 48 contiguous states or
Hawaii. A party that simply adds renewable fuel to gasoline or diesel
fuel, as defined in Sec. 80.1407(c) or (f), is not an obligated party.
(2) If the Administrator approves a petition of Alaska or a United
States territory to opt-in to the renewable fuel program under the
provisions in Sec. 80.1443, then ``obligated party'' shall also
include any refiner that produces gasoline or diesel fuel within that
state or territory, or any importer that imports gasoline or diesel
fuel into that state or territory.
(b) For each compliance period starting with 2010, an obligated
party is required to demonstrate, pursuant to Sec. 80.1427, that it
has satisfied the Renewable Volume Obligations for that compliance
period, as specified in Sec. 80.1407(a).
[[Page 25116]]
(c) An obligated party may comply with the requirements of
paragraph (b) of this section for all of its refineries in the
aggregate, or for each refinery individually.
(d) An obligated party must comply with the requirements of
paragraph (b) of this section for all of its imported gasoline or
diesel fuel in the aggregate.
(e) An obligated party that is both a refiner and importer must
comply with the requirements of paragraph (b) of this section for its
imported gasoline or diesel fuel separately from gasoline or diesel
fuel produced by its refinery or refineries.
(f) Where a refinery or import facility is jointly owned by two or
more parties, the requirements of paragraph (b) of this section may be
met by one of the joint owners for all of the gasoline or diesel fuel
produced/imported at the facility, or each party may meet the
requirements of paragraph (b) of this section for the portion of the
gasoline or diesel fuel that it owns, as long as all of the gasoline or
diesel fuel produced/imported at the facility is accounted for in
determining the Renewable Volume Obligations under Sec. 80.1407.
(g) The requirements in paragraph (b) of this section apply to the
following compliance periods: Beginning in 2010, and every year
thereafter, the compliance period is January 1 through December 31.
(h) A party that exports renewable fuel (pursuant to the definition
of an exporter of renewable fuel in Sec. 80.1401) shall demonstrate,
pursuant to Sec. 80.1427, that it has satisfied the Renewable Volume
Obligations for each compliance period as specified in Sec.
80.1430(b).
Sec. 80.1407 How are the Renewable Volume Obligations calculated?
(a) The Renewable Volume Obligations for an obligated party are
determined according to the following formulas:
(1) Cellulosic biofuel.
RVOCB,i = (RFStdCB,i * (GVi +
DVi)) + DCB,i-1
Where:
RVOCB,i = The Renewable Volume Obligation for cellulosic
biofuel for an obligated party for calendar year i, in gallons.
RFStdCB,i = The standard for cellulosic biofuel for
calendar year i, determined by EPA pursuant to Sec. 80.1405, in
percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced in or imported into the 48 contiguous states or Hawaii
by an obligated party in calendar year i, in gallons.
DVi = The diesel non-renewable volume, determined in
accordance with paragraphs (e) and (f) of this section, produced in
or imported into the 48 contiguous states or Hawaii by an obligated
party in calendar year i, in gallons.
DCB,i-1 = Deficit carryover from the previous year for
cellulosic biofuel, in gallons.
(2) Biomass-based diesel.
RVOBBD,i = (RFStdBBD,i * (GVi +
DVi)) + DBBD,i-1
Where:
RVOBBD,i = The Renewable Volume Obligation for biomass-
based diesel for an obligated party for calendar year i, in gallons.
RFStdBBD,i = The standard for biomass-based diesel for
calendar year i, determined by EPA pursuant to Sec. 80.1405, in
percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced in or imported into the 48 contiguous states or Hawaii
by an obligated party in calendar year i, in gallons.
DVi = The diesel non-renewable volume, determined in
accordance with paragraphs (e) and (f) of this section, produced in
or imported into the 48 contiguous states or Hawaii by an obligated
party in calendar year i, in gallons.
DBBD,i-1 = Deficit carryover from the previous year for
biomass-based diesel, in gallons.
(3) Advanced biofuel.
RVOAB,i = (RFStdAB,i * (GVi +
DVi)) + DAB,i-1
Where:
RVOAB,i = The Renewable Volume Obligation for advanced
biofuel for an obligated party for calendar year i, in gallons.
RFStdAB,i = The standard for advanced biofuel for
calendar year i, determined by EPA pursuant to Sec. 80.1405, in
percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced in or imported into the 48 contiguous states or Hawaii
by an obligated party in calendar year i, in gallons.
DVi = The diesel non-renewable volume, determined in
accordance with paragraphs (e) and (f) of this section, produced in
or imported into the 48 contiguous states or Hawaii by an obligated
party in calendar year i, in gallons.
DAB,i-1 = Deficit carryover from the previous year for
advanced biofuel, in gallons.
(4) Renewable fuel.
RVORF,i = (RFStdRF,i * (GVi +
DVi)) + DRF,i-1
Where:
RVORF,i = The Renewable Volume Obligation for renewable
fuel for an obligated party for calendar year i, in gallons.
RFStdRF,i = The standard for renewable fuel for calendar
year i, determined by EPA pursuant to Sec. 80.1405, in percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced in or imported into the 48 contiguous states or Hawaii
by an obligated party in calendar year i, in gallons.
DVi = The diesel non-renewable volume, determined in
accordance with paragraphs (e) and (f) of this section, produced in
or imported into the 48 contiguous states or Hawaii by an obligated
party in calendar year i, in gallons.
DRF,i-1 = Deficit carryover from the previous year for
renewable fuel, in gallons.
(b) The non-renewable gasoline volume for an obligated party for a
given year, GVi, specified in paragraph (a) of this section
is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP26MY09.016
Where:
x = Individual batch of gasoline produced or imported in calendar
year i.
n = Total number of batches of gasoline produced or imported in
calendar year i.
Gx = Volume of batch x of gasoline produced or imported,
as defined in paragraph (c) of this section, in gallons.
y = Individual batch of renewable fuel blended into gasoline in
calendar year i.
m = Total number of batches of renewable fuel blended into gasoline
in calendar year i.
RBGy = Volume of batch y of renewable fuel blended into
gasoline, in gallons.
(c) All of the following products that are produced or imported
during a compliance period, collectively called ``gasoline'' for the
purposes of this section (unless otherwise specified), are to be
included (but not double-counted) in the volume used to calculate a
party's Renewable Volume Obligations under paragraph (a) of this
section, except as provided in paragraph (d) of this section:
(1) Reformulated gasoline, whether or not renewable fuel is later
added to it.
(2) Conventional gasoline, whether or not renewable fuel is later
added to it.
(3) Reformulated gasoline blendstock that becomes finished
reformulated gasoline upon the addition of oxygenate (RBOB).
(4) Conventional gasoline blendstock that becomes finished
conventional gasoline upon the addition of oxygenate (CBOB).
(5) Blendstock (including butane and gasoline treated as blendstock
(GTAB)) that has been combined with other blendstock and/or finished
gasoline to produce gasoline.
(6) Any gasoline, or any unfinished gasoline that becomes finished
gasoline upon the addition of oxygenate, that is
[[Page 25117]]
produced or imported to comply with a state or local fuels program.
(d) The following products are not included in the volume of
gasoline produced or imported used to calculate a party's renewable
volume obligation under paragraph (a) of this section:
(1) Any renewable fuel as defined in Sec. 80.1401.
(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, 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. 80.1443.
(4) Gasoline produced by a small refinery that has an exemption
under Sec. 80.1441 or an approved small refiner that has an exemption
under Sec. 80.1442 until January 1, 2011 (or later, for small
refineries, if their exemption is extended pursuant to Sec.
80.1441(h)).
(5) Gasoline exported for use outside the 48 United States and
Hawaii, and gasoline exported for use outside Alaska, the Commonwealth
of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the
Commonwealth of the Northern Marianas, if the area has opted into the
RFS program under Sec. 80.1443.
(6) For blenders, the volume of finished gasoline, RBOB, or CBOB to
which a blender adds blendstocks.
(7) The gasoline portion of transmix produced by a transmix
processor, or the transmix blended into gasoline by a transmix blender,
under Sec. 80.84.
(e) The diesel non-renewable volume for an obligated party for a
given year, DVi, specified in paragraph (a) of this section
is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP26MY09.017
Where:
x = Individual batch of diesel produced or imported in calendar year
i.
n = Total number of batches of diesel produced or imported in
calendar year i.
Dx = Volume of batch x of diesel produced or imported, as
defined in paragraph (f) of this section, in gallons.
y = Individual batch of renewable fuel blended into diesel in
calendar year i.
m = Total number of batches of renewable fuel blended into diesel in
calendar year i.
RBDy = Volume of batch y of renewable fuel blended into
diesel, in gallons.
(f) All products meeting the definition of MVNRLM diesel fuel at
Sec. 80.2(qqq) that are produced or imported during a compliance
period, collectively called ``diesel fuel'' for the purposes of this
section (unless otherwise specified), are to be included (but not
double-counted) in the volume used to calculate a party's Renewable
Volume Obligations under paragraph (a) of this section.
Sec. Sec. 80.1408-80.1414 [Reserved]
Sec. 80.1415 How are equivalence values assigned to renewable fuel?
(a)(1) Each gallon of a renewable fuel, or gallon equivalent
pursuant to paragraph (c) of this section, shall be assigned an
equivalence value by the producer or importer pursuant to paragraph (b)
or (c) of this section.
(2) The equivalence value is a number that is used to determine how
many gallon-RINs can be generated for a batch of renewable fuel
according to Sec. 80.1426.
(b) All renewable fuels shall have an equivalence value of 1.0.
(c) A gallon of renewable fuel is a physically measured unit of
volume for any fuel that exists as a liquid at 60 [deg]F and 1 atm, but
represents 77,930 Btu (lower heating value) for any fuel that exists as
a gas at 60 [deg]F and 1 atm.
Sec. 80.1416 Treatment of parties who produce or import new renewable
fuels and pathways.
(a)(1) Each renewable fuel producer or importer that produces or
imports a new renewable fuel, or uses a new pathway that can not
qualify for a D code as defined in Sec. 80.1426(d), must apply to use
a D code as specified in paragraph (b) of this section.
(2) EPA will review the application and may allow the use of an
appropriate D code for the combination of fuel type, feedstock, and
production process.
(3) Except as provided in paragraph (c) of this section, parties
that must apply to use a D code pursuant to paragraph (b) of this
section may not generate RINs for that new fuel or new combination fuel
type, feedstock, and production process until the Agency has reviewed
the application and updated Table 1 to Sec. 80.1426.
(b)(1) The application for a new renewable fuel or pathway shall
include all the following:
(i) A completed facility registration under Sec. 80.1450(b).
(ii) A technical justification that includes a description of the
renewable fuel, feedstock(s) used to make it, and the production
process.
(iii) Any additional information that the Agency needs to complete
a lifecycle Greenhouse Gas assessment of the new fuel or pathway.
(2) A company may only submit one application per pathway. If EPA
determines the application to be incomplete, per paragraph (b)(4) of
this section, then the company may resubmit.
(3) The application must be signed and certified as meeting all the
applicable requirements of this subpart by a responsible corporate
officer of the applicant organization.
(4) If EPA determines that the application is incomplete then EPA
will notify the applicant in writing that the application is incomplete
and will not be reviewed further. However, an amended application that
corrects the omission may be re-submitted for EPA review.
(5) If the fuel or pathway described in the application does not
meet the definition of renewable fuel in Sec. 80.1401, then EPA will
notify the applicant in writing that the application is denied and will
not be reviewed further.
(c)(1) A producer may use a temporary D code pending EPA review of
an application under paragraph (b) of this section if the producer is
producing renewable fuel from a fuel type and feedstock combination
listed in Table 1 to Sec. 80.1426, but where the renewable fuel
producer's production process is not listed. A producer using a
temporary D code, must do all the following:
(i) Provide information necessary under paragraph (b) of this
section and register under 40 CFR part 79 before introducing the fuel
into commerce.
(ii) Generate RINs using the temporary D code for all renewable
fuel produced using this combination fuel type, feedstock, and
production process.
(iii) When Table 1 to Sec. 80.1426 has been updated to include the
new fuel pathway, cease to use the temporary D code and use the
applicable D code in the table.
(iv) For existing fuel type and feedstock combinations that apply
to more than one D code, the producer must use the highest numerical
value from the applicable D codes as the temporary D code.
(2) Except if the application is deemed incomplete or denied
pursuant to paragraph (b)(3) or (b)(4) of this section, if Table 1 to
Sec. 80.1426 is not updated within 5 years of the initial receipt of a
company's application, the company must stop using the temporary D
code.
(3) A producer whose fuel pathway is ethanol made from starches in
a process that uses natural gas or coal for process heat may not use a
temporary D code for their fuel pathway.
(4) EPA may revoke the authority provided by this section for use
of a temporary D code at any time if any of the following occur:
[[Page 25118]]
(i) EPA determines that the fuel or pathway described in the
application does not meet the definition of renewable fuel in Sec.
80.1401.
(ii) EPA discovers adverse health effects unique to the fuel or
pathway.
(iii) The information provided by the applicant on the pathway in
paragraph (b) of this section is deemed false or incorrect.
(d) The application under this section shall be submitted on forms
and following procedures as prescribed by EPA.
Sec. Sec. 80.1417-80.1424 [Reserved]
Sec. 80.1425 Renewable Identification Numbers (RINs).
Each RIN is a 38-character numeric code of the following form:
KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
(a) K is a number identifying the type of RIN as follows:
(1) K has the value of 1 when the RIN is assigned to a volume of
renewable fuel pursuant to Sec. Sec. 80.1426(e) and 80.1428(a).
(2) K has the value of 2 when the RIN has been separated from a
volume of renewable fuel pursuant to Sec. 80.1429.
(b) YYYY is the calendar year in which the batch of renewable fuel
was produced or imported. YYYY also represents the year in which the
RIN was originally generated.
(c) CCCC is the registration number assigned, according to Sec.
80.1450, to the producer or importer of the batch of renewable fuel.
(d) FFFFF is the registration number assigned, according to Sec.
80.1450, to the facility at which the batch of renewable fuel was
produced or imported.
(e) BBBBB is a serial number assigned to the batch which is chosen
by the producer or importer of the batch such that no two batches have
the same value in a given calendar year.
(f) RR is a number representing 10 times the equivalence value of
the renewable fuel as specified in Sec. 80.1415.
(g) D is a number determined according to Sec. 80.1426(d) and
identifying the type of renewable fuel, as follows:
(1) D has the value of 1 to denote fuel categorized as cellulosic
biofuel.
(2) D has the value of 2 to denote fuel categorized as biomass-
based diesel.
(3) D has the value of 3 to denote fuel categorized as advanced
biofuel.
(4) D has the value of 4 to denote fuel categorized as renewable
fuel.
(h) SSSSSSSS is a number representing the first gallon-RIN
associated with a batch of renewable fuel.
(i) EEEEEEEE is a number representing the last gallon-RIN
associated with a batch of renewable fuel. EEEEEEEE will be identical
to SSSSSSSS if the batch-RIN represents a single gallon-RIN. Assign the
value of EEEEEEEE as described in Sec. 80.1426.
Sec. 80.1426 How are RINs generated and assigned to batches of
renewable fuel by renewable fuel producers or importers?
(a) Regional applicability. (1) Except as provided in paragraph (b)
of this section, a RIN must be generated by a renewable fuel producer
or importer for every batch of fuel that meets the definition of
renewable fuel that is produced or imported for use as transportation
fuel, home heating oil, or jet fuel in the 48 contiguous states or
Hawaii.
(2) If the Administrator approves a petition of Alaska or a United
States territory to opt-in to the renewable fuel program under the
provisions in Sec. 80.1443, then the requirements of paragraph (a)(1)
of this section shall also apply to renewable fuel produced or imported
for use as transportation fuel, home heating oil, or jet fuel in that
state or territory beginning in the next calendar year.
(b) Cases in which RINs are not generated. (1) Volume threshold.
Renewable fuel producers 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. 80.1450 through 80.1452, and the attest
engagement requirements of Sec. 80.1464. However, for those producers
and importers that own RINs or voluntarily generate and assign RINs,
all the requirements of this subpart apply.
(2) Fuel producers and importers shall not generate RINs for fuel
that they produce or import for which they have made a demonstration
under Sec. 80.1451(c) that the feedstocks used to produce the fuel are
not renewable biomass (as defined in Sec. 80.1401).
(3) Fuel producers and importers may not generate RINs for fuel
that is not renewable fuel.
(4) Importers shall not import or generate RINs for fuel imported
from a foreign producer that is not registered with EPA as required in
Sec. 80.1450.
(5) Importers shall not generate RINs for renewable fuel that has
already been assigned RINs by a foreign producer.
(c) Definition of batch. For the purposes of this section and Sec.
80.1425, a ``batch of renewable fuel'' is a volume of renewable fuel
that has been assigned a unique RIN code BBBBB within a calendar year
by the producer or importer of the renewable fuel in accordance with
the provisions of this section and Sec. 80.1425.
(1) The number of gallon-RINs generated for a batch of renewable
fuel may not exceed 99,999,999.
(2) A batch of renewable fuel cannot represent renewable fuel
produced or imported in excess of one calendar month.
(d) Generation of RINs. (1) Producers and importers of fuel made
from renewable feedstocks must determine for each batch of fuel
produced or imported whether or not the fuel is renewable fuel (as
defined in Sec. 80.1401), including a determination of whether or not
the feedstock used to make the fuel is renewable biomass (as defined
Sec. 80.1401). Except as provided in paragraph (b) of this section,
the producer or importer of a batch of renewable fuel must generate a
RIN for that batch.
(i) Domestic producers must generate RINs for all renewable fuel
that they produce.
(ii) Importers must generate RINs for all renewable fuel that they
import that has not been assigned RINs by a foreign producer, including
any renewable fuel contained in imported transportation fuel.
(iii) Foreign producers may generate RINs for any renewable fuel
that they export to the 48 contiguous states of the United States or
Hawaii.
(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. 80.1425(a) and this paragraph (d).
(3) Applicable pathways. D codes shall be used in RINs generated by
producers or importers of renewable fuel according to the pathways
listed in Table 1 to this section.
[[Page 25119]]
Table 1 to Sec. 80.1426--Applicable D Codes For Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
Production process
Fuel type Feedstock requirements D code
----------------------------------------------------------------------------------------------------------------
Ethanol................................. Starch from corn, wheat, --Process heat derived 4
barley, oats, rice, or sorghum. from biomass
Ethanol................................. Starch from corn, wheat, --Dry mill plant.......... 4
barley, oats, rice, or sorghum. --Process heat derived
from natural gas.
--Combined heat and power
(CHP).
--Fractionation of
feedstocks.
--Some or all distillers
grains are dried.
Ethanol................................. Starch from corn, wheat, --Dry mill plant.......... 4
barley, oats, rice, or sorghum. --Process heat derived
from natural gas.
--All distillers grains
are wet.
Ethanol................................. Starch from corn, wheat, --Dry mill plant.......... 4
barley, oats, rice, or sorghum. --Process heat derived
from coal.
--Combined heat and power
(CHP).
--Fractionation of
feedstocks.
--Membrane separation of
ethanol.
--Raw starch hydrolysis...
--Some or all distillers
grains are dried.
Ethanol................................. Starch from corn, wheat, --Dry mill plant.......... 4
barley, oats, rice, or sorghum. --Process heat derived
from coal.
--Combined heat and power
(CHP).
--Fractionation of
feedstocks.
--Membrane separation of
ethanol.
--All distillers grains
are wet.
Ethanol................................. Cellulose and hemicellulose --Enzymatic hydrolysis of 1
from corn stover, switchgrass, cellulose.
miscanthus, wheat straw, rice --Fermentation of sugars..
straw, sugarcane bagasse, --Process heat derived
slash, pre-commercial from lignin.
thinnings, yard waste, or
planted trees.
Ethanol................................. Cellulose and hemicellulose --Thermochemical 1
from corn stover, switchgrass, gasification of biomass.
miscanthus, wheat straw, rice --Fischer-Tropsch process.
straw, sugarcane bagasse,
slash, pre-commercial
thinnings, yard waste, or
planted trees.
Ethanol................................. Sugarcane sugar................ --Process heat derived 3
from sugarcane bagasse
Biodiesel (mono alkyl ester)............ Waste grease, waste oils, --Transesterification..... 2
tallow, chicken fat, or non-
food-grade corn oil.
Biodiesel (mono alkyl ester)............ Soybean oil and other virgin --Transesterification..... 4
plant oils.
Cellulosic diesel....................... Cellulose and hemicellulose --Thermochemical 1 or 2
from corn stover, switchgrass, gasification of biomass.
miscanthus, wheat straw, rice --Fischer-Tropsch process.
straw, sugarcane bagasse, --Catalytic
slash, pre-commercial depolymerization.
thinnings, yard waste, or
planted trees.
Non-ester renewable diesel.............. Waste grease, waste oils, --Hydrotreating........... 2
tallow, chicken fat, or non- --Dedicated facility that
food-grade corn oil. processes only renewable
biomass.
Non-ester renewable diesel.............. Waste grease, waste oils, --Hydrotreating........... 3
tallow, chicken fat, or non- --Co-processing facility
food-grade corn oil. that also processes
petroleum feedstocks.
Non-ester renewable diesel.............. Soybean oil and other virgin --Hydrotreating........... 4
plant oils.
Cellulosic gasoline..................... Cellulose and hemicellulose --Thermochemical 1
from corn stover, switchgrass, gasification of biomass.
miscanthus, wheat straw, rice --Fischer-Tropsch process.
straw, sugarcane bagasse, --Catalytic
slash, pre-commercial depolymerization.
thinnings, yard waste, or
planted trees.
----------------------------------------------------------------------------------------------------------------
(4) Producers whose operations can be described by a single
pathway.
(i) The number of gallon-RINs that shall be generated for a given
batch of renewable fuel shall be equal to a volume calculated according
to the following formula:
VRIN = EV * Vs
Where:
VRIN = RIN volume, in gallons, for use in determining the
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
(ii) The D code that shall be used in the RINs generated shall be
the D code specified in Table 1 to this section which corresponds to
the pathway that describes the producer's operations.
(5) Producers whose operations can be described by two or more
pathways. (i) The D codes that shall be used in the RINs generated
within a calendar year shall be the D codes specified in Table 1 to
this section which correspond to the pathways that describe the
producer's operations throughout that calendar year.
(ii) If all the pathways describing the producer's operations have
the same D code, then that D code shall be used in all the RINs
generated. The number of gallon-RINs that shall be generated for a
[[Page 25120]]
given batch of renewable fuel in this case shall be equal to a volume
calculated according to the following formula:
VRIN = EV * Vs
Where:
VRIN = RIN volume, in gallons, for use in determining the
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
(iii) If the pathway applicable to a producer changes on a specific
date, such that one pathway applies before the date and another pathway
applies on and after the date, then the applicable D code used in
generating RINs must change on the date that the change in pathway
occurs. The number of gallon-RINs that shall be generated for a given
batch of renewable fuel in this case shall be equal to a volume
calculated according to the following formula:
VRIN = EV * Vs
Where:
VRIN = RIN volume, in gallons, for use in determining the
number of gallon-RINs that shall be generated for a batch with a
single applicable D code.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
(iv) If a producer produces two or more different types of
renewable fuel whose volumes can be measured separately, then separate
values for VRIN shall be calculated for each batch of each
type of renewable fuel according to formulas in Table 2 to this
section:
Table 2 to Sec. 80.1426--Number of Gallon-RINs To Assign to Batch-RINs
with D Codes Dependent on Fuel Type
------------------------------------------------------------------------
D code to use in batch-RIN Number of gallon-RINs
------------------------------------------------------------------------
D = 1..................................... VRIN, CB = EV *Vs, CB
D = 2..................................... VRIN, BBD = EV *Vs, BBD
D = 3..................................... VRIN, AB = EV *Vs, RF
D = 4..................................... VRIN, RF = EV *Vs, RF
------------------------------------------------------------------------
Where:
VRIN,CB = RIN volume, in gallons, for use determining the
number of gallon-RINs that shall be generated for a batch of
cellulosic biofuel with a D code of 1.
VRIN,BBD = RIN volume, in gallons, for use determining
the number of gallon-RINs that shall be generated for a batch of
biomass-based diesel with a D code of 2.
VRIN,AB = RIN volume, in gallons, for use determining the
number of gallon-RINs that shall be generated for a batch of
advanced biofuel with a D code of 3.
VRIN,RF = RIN volume, in gallons, for use determining the
number of gallon-RINs that shall be generated for a batch of
renewable fuel with a D code of 4.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs,CB = Standardized volume of the batch of renewable
fuel at 60 [deg]F that must be assigned a D code of 1 based on its
fuel type, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
Vs,BBD = Standardized volume of the batch of renewable
fuel at 60 [deg]F that must be assigned a D code of 2 based on its
fuel type, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
Vs,AB = Standardized volume of the batch of renewable
fuel at 60 [deg]F that must be assigned a D code of 3 based on its
fuel type, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
Vs,RF = Standardized volume of the batch of renewable
fuel at 60 [deg]F that must be assigned a D code of 4 based on its
fuel type, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
(v) If a producer produces a single type of renewable fuel using
two or more different feedstocks which are processed simultaneously,
then the number of gallon-RINs that shall be generated for each batch
of renewable fuel and assigned a particular D code shall be determined
according to the formulas in Table 3 to this section.
[GRAPHIC] [TIFF OMITTED] TP26MY09.018
Where:
VRIN,CB = RIN volume, in gallons, for use in determining
the number of gallon-RINs that shall be generated for a batch of
cellulosic biofuel with a D code of 1.
VRIN,BBD = RIN volume, in gallons, for use in determining
the number of gallon-RINs that shall be generated for a batch of
biomass-based diesel with a D code of 2.
VRIN,AB = RIN volume, in gallons, for use in determining
the number of gallon-RINs that shall be generated for a batch of
advanced biofuel with a D code of 3.
VRIN,RF = RIN volume, in gallons, for use in determining
the number of gallon-RINs that shall be generated for a batch of
renewable fuel with a D code of 4.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
FE1 = Feedstock energy from all feedstocks whose pathways
have been assigned a D code of 1 under Table 1 to this section, in
Btu.
FE2 = Feedstock energy from all feedstocks whose pathways
have been assigned a D code of 2 under Table 1 to this section, in
Btu.
FE3 = Feedstock energy from all feedstocks whose pathways
have been assigned a D code of 3 under Table 1 to this section, in
Btu.
FE4 = Feedstock energy from all feedstocks whose pathways
have been assigned a D
[[Page 25121]]
code of 4 under Table 1 to this section, in Btu.
Feedstock energy values, FE, shall be calculated according to the
following formula:
FE = M * CF * E
Where:
FE = Feedstock energy, in Btu.
M = Mass of feedstock, in pounds.
CF = Converted Fraction in annual average mass percent, representing
that portion of the feedstock that is estimated to be converted into
renewable fuel by the producer.
E = Energy content of the fuel precursor fraction for the feedstock
in annual average Btu/lb.
(6) Producers who co-process renewable biomass and fossil fuels
simultaneously to produce a transportation fuel that is partially
renewable. (i) The number of gallon-RINs that shall be generated for a
given batch of partially renewable transportation fuel shall be equal
to a volume calculated according to the following formula:
VRIN = EV * Vs * FER/(FER +
FEF)
Where:
VRIN = RIN volume, in gallons, for use in determining the
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
FER = Feedstock energy from renewable biomass used to
make the transportation fuel, in Btu.
FEF = Feedstock energy from fossil fuel used to make the
transportation fuel, in Btu.
(ii) The value of FE for use in paragraph (d)(6)(i) of this section
shall be calculated from the following formula:
FE = M * CF * E
Where:
FE = Feedstock energy, in Btu.
M = Mass of feedstock, in pounds.
CF = Converted Fraction in annual average mass percent, representing
that portion of the feedstock that is estimated to be converted into
transportation fuel by the producer.
E = Energy content of the fuel precursor fraction for the feedstock,
in annual average Btu/lb.
(iii) The D code that shall be used in the RINs generated to
represent partially renewable transportation fuel shall be the D code
specified in Table 1 to this section which corresponds to the pathway
that describes a producer's operations. In determining the appropriate
pathway, the contribution of fossil fuel feedstocks to the production
of partially renewable fuel shall be ignored.
(7) Producers without an applicable pathway. (i) If none of the
pathways described in Table 1 to this section apply to a producer's
operations, a party generating a RIN may nevertheless use a pathway in
Table 1 to this section if EPA allows the use of a temporary D code
pursuant to Sec. 80.1416(c).
(ii) If none of the pathways described in Table 1 to this section
apply to a producer's operations and the party generating the RIN does
not qualify to use a temporary D code according to the provisions of
Sec. 80.1416(c), the party must generate RINs if the fuel from its
facility qualifies for grandfathering as provided in Sec. 80.1403.
(A) The number of gallon-RINs that shall be generated for a given
batch of grandfathered renewable fuel shall be equal to a volume
calculated according to the following formula:
VRIN = EV * Vs
Where:
VRIN = RIN volume, in gallons, for use in determining the
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60[deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
(B) A D code of 4 shall be used in the RINs generated under
paragraph (d)(7)(ii)(A) of this section.
(8) Provisions for importers of renewable fuel. (i) The number of
gallon-RINs that shall be generated for a given batch of renewable fuel
shall be equal to a volume calculated according to the following
formula:
VRIN = EV * Vs
Where:
VRIN = RIN volume, in gallons, for use in determining the
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1415.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(10) of this section.
(ii) The D code that shall be used in the RINs generated by an
importer of renewable fuel shall be determined from information
provided by the foreign producer specifying the applicable pathway or
pathways for the renewable fuel and the provisions of this paragraph
(d).
(9) Multiple gallon-RINs generated to represent a given volume of
renewable fuel can be represented by a single batch-RIN through the
appropriate designation of the RIN volume codes SSSSSSSS and EEEEEEEE.
(i) The value of SSSSSSSS in the batch-RIN shall be 00000001 to
represent the first gallon-RIN associated with the volume of renewable
fuel.
(ii) The value of EEEEEEEE in the batch-RIN shall represent the
last gallon-RIN associated with the volume of renewable fuel, based on
the RIN volume determined pursuant to paragraph (d)(4) of this section.
(10) Standardization of volumes. In determining the standardized
volume of a batch of renewable fuel for purposes of generating RINs
under this paragraph (d), the batch volumes shall be adjusted to a
standard temperature of 60 [deg]F.
(i) For ethanol, the following formula shall be used:
Vs,e = Va,e * (-0.0006301 * T + 1.0378)
Where:
Vs,e = Standardized volume of ethanol at 60 [deg]F, in
gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.
(ii) For biodiesel (mono-alkyl esters), the following formula shall
be used:
Vs,b = Va,b * (-0.0008008 * T + 1.0480)
Where:
Vs,b = Standardized volume of biodiesel at 60 [deg]F, in
gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.
(iii) For other renewable fuels, an appropriate formula commonly
accepted by the industry shall be used to standardize the actual volume
to 60 [deg]F. Formulas used must be reported to EPA, and may be
reviewed for appropriateness.
(11)(i) A party is prohibited from generating RINs for a volume of
fuel that it produces if:
(A) The fuel has been produced from a chemical conversion process
that uses another renewable fuel as a feedstock, and the renewable fuel
used as a feedstock was produced by another party; or
(B) The fuel is not produced from renewable biomass.
(ii) Parties who produce renewable fuel made from a feedstock which
itself was a renewable fuel with RINs, shall assign the original RINs
to the new renewable fuel.
(e) Assignment of RINs to batches. (1) The producer or importer of
renewable fuel must assign all RINs generated to volumes of renewable
fuel.
(2) A RIN is assigned to a volume of renewable fuel when ownership
of the RIN is transferred along with the transfer of ownership of the
volume of renewable fuel, pursuant to Sec. 80.1428(a).
(3) All assigned RINs shall have a K code value of 1.
(4) Any RINs generated but not assigned to a volume of renewable
fuel must be counted with assigned RINs in
[[Page 25122]]
the quarterly RIN and volume inventory balance check calculation
required in Sec. 80.1428.
Sec. 80.1427 How are RINs used to demonstrate compliance?
(a) Renewable Volume Obligations. (1) Except as specified in
paragraph (b) of this section or Sec. 80.1455, each party that is
obligated to meet the Renewable Volume Obligations under Sec. 80.1407,
or each party that is an exporter of renewable fuels that is obligated
to meet Renewable Volume Obligations under Sec. 80.1430, must
demonstrate pursuant to Sec. 80.1452(a)(1) that it owns sufficient
RINs to satisfy the following equations:
(i) Cellulosic biofuel.
([Sigma]RINNUM)CB,i + ([Sigma]RINNUM)CB,i-1 =
RVOCB,i
Where:
([Sigma]RINNUM)CB,i = Sum of all owned gallon-RINs that
are valid for use in complying with the cellulosic biofuel RVO, were
generated in year i, and are being applied towards the
RVOCB,i, in gallons.
([Sigma]RINNUM)CB,i-1 = Sum of all owned gallon-RINs that
are valid for use in complying with the cellulosic biofuel RVO, were
generated in year i-1, and are being applied towards the
RVOCB,i, in gallons.
RVOCB,i = The Renewable Volume Obligation for cellulosic
biofuel for the obligated party or renewable fuel exporter for
calendar year i, in gallons, pursuant to Sec. 80.1407 or Sec.
80.1430.
(ii) Biomass-based diesel.
([Sigma]RINNUM)BBD,i + ([Sigma]RINNUM)BBD,i-1 =
RVOBBD,i
Where:
([Sigma]RINNUM)BBD,i = Sum of all owned gallon-RINs that
are valid for use in complying with the biomass-based diesel RVO,
were generated in year i, and are being applied towards the
RVOBBD,i, in gallons.
([Sigma]RINNUM)BBD,i-1 = Sum of all owned gallon-RINs
that are valid for use in complying with the biomass-based diesel
RVO, were generated in year i-1, and are being applied towards the
RVOBBD,i, in gallons.
RVOBBD,i = The Renewable Volume Obligation for biomass-
based diesel for the obligated party or renewable fuel exporter for
calendar year i after 2010, in gallons, pursuant to Sec. 80.1407 or
Sec. 80.1430.
(iii) Advanced biofuel.
([Sigma]RINNUM)AB,i + ([Sigma]RINNUM)AB,i-1 =
RVOAB,i
Where:
([Sigma]RINNUM)AB,i = Sum of all owned gallon-RINs that
are valid for use in complying with the advanced biofuel RVO, were
generated in year i, and are being applied towards the
RVOAB,i, in gallons.
([Sigma]RINNUM)AB,i-1 = Sum of all owned gallon-RINs that
are valid for use in complying with the advanced biofuel RVO, were
generated in year i-1, and are being applied towards the
RVOAB,i, in gallons.
RVOAB,i = The Renewable Volume Obligation for advanced
biofuel for the obligated party or renewable fuel exporter for
calendar year i, in gallons, pursuant to Sec. 80.1407 or Sec.
80.1430.
(iv) Renewable fuel.
([Sigma]RINNUM)RF,i + ([Sigma]RINNUM)RF,i-1 =
RVORF,i
Where:
([Sigma]RINNUM)RF,i = Sum of all owned gallon-RINs that
are valid for use in complying with the renewable fuel RVO, were
generated in year i, and are being applied towards the
RVORF,i, in gallons.
([Sigma]RINNUM)RF,i-1 = Sum of all owned gallon-RINs that
are valid for use in complying with the renewable fuel RVO, were
generated in year i-1, and are being applied towards the
RVORF,i, in gallons.
RVORF,i = The Renewable Volume Obligation for renewable
fuel for the obligated party or renewable fuel exporter for calendar
year i, in gallons, pursuant to Sec. 80.1407 or Sec. 80.1430.
(2) Except as described in paragraph (a)(3) of this section, RINs
that are valid for use in complying with each Renewable Volume
Obligation are determined by their D codes.
(i) RINs with a D code of 1 are valid for compliance with the
cellulosic biofuel RVO.
(ii) RINs with a D code of 2 are valid for compliance with the
biomass-based diesel RVO.
(iii) RINs with a D code of 1, 2, or 3 are valid for compliance
with the advanced biofuel RVO.
(iv) RINs with a D code of 1, 2, 3, or 4 are valid for compliance
with the renewable fuel RVO.
(3) For purposes of demonstrating compliance for calendar year
2010, RINs generated in 2009 pursuant to Sec. 80.1126 that are not
used for compliance purposes for calendar year 2009 may be used for
compliance in 2010, insofar as permissible pursuant to paragraphs
(a)(5) and (a)(7)(iv) of this section, as follows:
(i) A 2009 RIN with an RR code of 15 or 17 is deemed equivalent to
a RIN generated pursuant to Sec. 80.1426 having a D code of 2.
(ii) A 2009 RIN with a D code of 1 is deemed equivalent to a RIN
generated pursuant to Sec. 80.1426 having a D code of 1.
(iii) All other 2009 RINs are deemed equivalent to RINs generated
pursuant to Sec. 80.1426 having D codes of 4.
(iv) A 2009 RIN that is retired pursuant to Sec. 80.1129(e)
because the associated volume of fuel is not used as motor vehicle fuel
may be reinstated pursuant to Sec. 80.1429(f)(1).
(4) A party may use the same RIN to demonstrate compliance with
more than one RVO so long as it is valid for compliance with all RVOs
to which it is applied.
(5) Except as provided in paragraph (a)(7)(iv) of this section, the
value of ([Sigma]RINNUM)i-1 may not exceed values determined
by the following inequalities:
([Sigma]RINNUM)CB,i-1 <= 0.20 * RVOCB,i
([Sigma]RINNUM)BBD,i-1 <= 0.20 * RVOBBD,i
([Sigma]RINNUM)AB,i-1 <= 0.20 * RVOAB,i
([Sigma]RINNUM)RF,i-1 <= 0.20 * RVORF,i
(6) Except as provided in paragraphs (a)(7)(ii) and (iii) of this
section, RINs may only be used to demonstrate compliance with the RVOs
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.
(7) Biomass-based diesel in 2010. (i) Prior to determining
compliance with the 2010 biomass-based diesel RVO, obligated parties
may reduce the value of RVOBBD,2010 by an amount equal to
the sum of all 2008 and 2009 RINs used for compliance purposes for
calendar year 2009 which have an RR code of 15 or 17.
(ii) For calendar year 2010 only, the following equation shall be
used to determine compliance with the biomass-based diesel RVO instead
of the equation in paragraph (a)(1)(ii) of this section:
([Sigma]RINNUM)BBD,2010 + ([Sigma]RINNUM)BBD,2009
+ ([Sigma]RINNUM)BBD,2008 = RVOBBD,2010
Where:
([Sigma]RINNUM)BBD,2010 = Sum of all owned gallon-RINs
that are valid for use in complying with the biomass-based diesel
RVO, were generated in year 2010, and are being applied towards the
RVOBBD,2010, in gallons.
([Sigma]RINNUM)BBD,2009 = Sum of all owned gallon-RINs
that are valid for use in complying with the biomass-based diesel
RVO, were generated in year 2009, have not previously been used for
compliance purposes, and are being applied towards the
RVOBBD,2010, in gallons.
([Sigma]RINNUM)BBD,2008 = Sum of all owned gallon-RINs
that are valid for use in complying with the biomass-based diesel
RVO, were generated in year 2008, have not previously been used for
compliance purposes, and are being applied towards the
RVOBBD,2010, in gallons.
RVOBBD,2010 = The Renewable Volume Obligation for
biomass-based diesel for the obligated party or renewable fuel
exporter for calendar year 2010, in gallons, pursuant to Sec.
80.1407 or Sec. 80.1430, as adjusted by paragraph (a)(7)(i) of this
section.
(iii) RINs generated in 2008 or 2009 which have not been used for
[[Page 25123]]
compliance purposes for calendar years 2008 or 2009 and which have an
RR code of 15 or 17 may be used to demonstrate compliance with the 2010
biomass-based diesel RVO.
(iv) For compliance with the biomass-based diesel RVO in calendar
year 2010 only, the values of ([Sigma]RINNUM)2008 and
([Sigma]RINNUM)2009 may not exceed values determined by both
of the following inequalities:
([Sigma]RINNUM)BBD,2008 <= 0.087 * RVOBBD,2010
([Sigma]RINNUM)BBD,2008 + ([Sigma]RINNUM)BBD,2009
<= 0.20 * RVOBBD,2010
(8) A party may only use a RIN for purposes of meeting the
requirements of paragraph (a)(1) of this section if that RIN is a
separated RIN with a K code of 2 obtained in accordance with Sec. Sec.
80.1428 and 80.1429.
(9) The number of gallon-RINs associated with a given batch-RIN
that can be used for compliance with the RVOs shall be calculated from
the following formula:
RINNUM = EEEEEEEE-SSSSSSSS + 1
Where:
RINNUM = Number of gallon-RINs associated with a batch-RIN, where
each gallon-RIN represents one gallon of renewable fuel for
compliance purposes.
EEEEEEEE = Batch-RIN component identifying the last gallon-RIN
associated with the batch-RIN.
SSSSSSSS = Batch-RIN component identifying the first gallon-RIN
associated with the batch-RIN.
(b) Deficit carryovers. (1) An obligated party or an exporter of
renewable fuel that fails to meet the requirements of paragraph (a)(1)
or (a)(5) 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 for the same RVO.
(ii) The party subsequently meets the requirements of paragraph
(a)(1) of this section for calendar year i+1 and carries no deficit
into year i+2 for the same RVO.
(iii) For compliance with the biomass-based diesel RVO in calendar
year 2011, the deficit which is carried over from 2010 is no larger
than 57% of the party's 2010 biomass-based diesel RVO as determined
prior to any adjustment applied pursuant to paragraph (a)(7)(i) of this
section.
(2) A deficit is calculated according to the following formula:
Di = RVOi-[([Sigma]RINNUM)i +
([Sigma]RINNUM)i-1]
Where:
Di = The deficit, in gallons, generated in calendar year
i that must be carried over to year i+1 if allowed to do so pursuant
to paragraph (b)(1) of this section.
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons.
([Sigma]RINNUM)i = Sum of all acquired gallon-RINs
that were generated in year i and are being applied towards the
RVOi, in gallons.
([Sigma]RINNUM)i-1 = Sum of all acquired gallon-RINs
that were generated in year i-1 and are being applied towards the
RVOi, in gallons.
Sec. 80.1428 General requirements for RIN distribution.
(a) RINs assigned to volumes of renewable fuel and RINs generated,
but not assigned. (1) Definitions. (i) Assigned RIN, for the purposes
of this subpart, means a RIN assigned to a volume of renewable fuel
pursuant to Sec. 80.1426(e) with a K code of 1.
(ii) RINS generated, but not assigned are those RINs that have been
generated pursuant to 80.1426(a), but have not been assigned to a
volume of renewable fuel pursuant to 80.1426(e).
(2) Except as provided in Sec. 80.1429, no party can separate a
RIN that has been assigned to a batch pursuant to Sec. 80.1426(e).
(3) An assigned RIN cannot be transferred to another party without
simultaneously transferring a volume of renewable fuel to that same
party.
(4) No more than 2.5 assigned gallon-RINs with a K code of 1 can be
transferred to another party with every gallon of renewable fuel
transferred to that same party.
(5)(i) On each of the dates listed in paragraph (a)(5)(ii) of this
section in any calendar year, the following equation must be satisfied
for assigned RINs and volumes of renewable fuel owned by a party:
[Sigma](RIN)D <= [Sigma](Vsi * 2.5)D
Where:
D = Applicable date.
[Sigma](RIN)D = Sum of all assigned gallon-RINs with a K
code of 1 and all RINs generated, but not assigned that are owned on
date D.
(Vsi)D = Volume i of renewable fuel owned on
date D, standardized to 60 [deg]F, in gallons.
[Sigma](Vsi * 2.5)D = Sum of all volumes of
renewable fuel owned on date D, multiplied by an equivalence value
of 2.5.
(ii) The applicable dates are March 31, June 30, September 30, and
December 31.
(6) Any transfer of ownership of assigned RINs must be documented
on product transfer documents generated pursuant to Sec. 80.1453.
(i) The RIN must be recorded on the product transfer document used
to transfer ownership of the volume of renewable fuel to another party;
or
(ii) The RIN must be recorded on a separate product transfer
document transferred to the same party on the same day as the product
transfer document used to transfer ownership of the volume of renewable
fuel.
(b) RINs separated from volumes of renewable fuel. (1) Separated
RIN, for the purposes of this subpart, means a RIN with a K code of 2
that has been separated from a volume of renewable fuel pursuant to
Sec. 80.1429.
(2) Any party that has registered pursuant to Sec. 80.1450 can
hold title to a separated RIN.
(3) Separated RINs can be transferred from one party to another any
number of times.
(c) RIN expiration. A RIN is valid for compliance during the year
in which it was generated, or the following year. Any RIN that is not
used for compliance purposes during the year that it was generated, or
during the following year, will be considered an expired RIN. Pursuant
to Sec. 80.1431(a)(3), an expired RIN that is used for compliance will
be considered an invalid RIN.
(d) Any batch-RIN can be divided by its owner into multiple batch-
RINs, each representing a smaller number of gallon-RINs, if all of the
following conditions are met:
(1) All RIN components other than SSSSSSSS and EEEEEEEE are
identical for the original parent and newly formed daughter RINs.
(2) The sum of the gallon-RINs associated with the multiple
daughter batch-RINs is equal to the gallon-RINs associated with the
parent batch-RIN.
Sec. 80.1429 Requirements for separating RINs from volumes of
renewable fuel.
(a)(1) Separation of a RIN from a volume of renewable fuel means
termination of the assignment of the RIN to a volume of renewable fuel.
(2) RINs that have been separated from volumes of renewable fuel
become separated RINs subject to the provisions of Sec. 80.1428(b).
(b) A RIN that is assigned to a volume of renewable fuel is
separated from that volume only under one of the following conditions:
(1) Except as provided in paragraph (b)(6) of this section, a party
that is an obligated party according to Sec. 80.1406 must separate any
RINs that have been assigned to a volume of renewable fuel if they own
that volume.
(2) Except as provided in paragraph (b)(5) of this section, any
party that owns a volume of renewable fuel must separate any RINs that
have been assigned to that volume once the volume is blended with
gasoline or diesel to produce a transportation fuel,
[[Page 25124]]
home heating oil, or jet fuel. A party may separate up to 2.5 RINs per
gallon of renewable fuel.
(3) Any party that exports a volume of renewable fuel must separate
any RINs that have been assigned to the exported volume.
(4) Any party that produces, imports, owns, sells, or uses a volume
of neat renewable fuel, or a blend of renewable fuel and diesel fuel,
must separate any RINs that have been assigned to that volume of neat
renewable fuel or that blend if:
(i) The party designates the neat renewable fuel or blend as
transportation fuel, home heating oil, or jet fuel: and
(ii) The neat renewable fuel or blend is used without further
blending, in the designated form, as transportation fuel, home heating
oil, or jet fuel.
(5) RINs assigned to a volume of biodiesel (mono-alkyl ester) can
only be separated from that volume pursuant to paragraph (b)(2) of this
section if such biodiesel is blended into diesel fuel at a
concentration of 80 volume percent biodiesel (mono-alkyl ester) or
less.
(i) This paragraph (b)(5) shall not apply to obligated parties or
exporters of renewable fuel.
(ii) This paragraph (b)(5) shall not apply to parties meeting the
requirements of paragraph (b)(4) of this section.
(6) For RINs that an obligated party generates for renewable fuel
that has not been blended into gasoline or diesel to produce a
transportation fuel, the obligated party can only separate such RINs
from volumes of renewable fuel if the number of gallon-RINs separated
in a calendar year is less than or equal to a limit set as follows:
(i) For RINs with a D code of 1, the limit shall be equal to
RVOCB.
(ii) For RINs with a D code of 2, the limit shall be equal to
RVOBBD.
(iii) For RINs with a D code of 3, the limit shall be equal to
RVOAB -- RVOCB--RVOBBD.
(iv) For RINs with a D code of 4, the limit shall be equal to
RVORF -- RVOAB.
(7) For a party that has received a small refinery exemption under
Sec. 80.1441 or a small refiner exemption under Sec. 80.1442, and is
not otherwise an obligated party, during the period of time that the
small refinery or small refiner exemptions are in effect, the party may
only separate RINs that have been assigned to volumes of renewable fuel
that the party blends into gasoline or diesel to produce transportation
fuel, or that the party used as home heating oil or jet fuel.
(c) The party responsible for separating a RIN from a volume of
renewable fuel shall change the K code in the RIN from a value of 1 to
a value of 2 prior to transferring the RIN to any other party.
(d) Upon and after separation of a RIN from its associated volume
of renewable fuel, the separated RIN must be accompanied by
documentation when transferred.
(1) When transferred, the separated RIN shall appear on
documentation that includes all the following information:
(i) The name and address of the transferor and transferee.
(ii) The transferor's and transferee's EPA company registration
numbers.
(iii) The date of the transfer.
(iv) A list of separated RINs transferred.
(2) [Reserved]
(e) Upon and after separation of a RIN from its associated volume
of renewable fuel, product transfer documents used to transfer
ownership of the volume must continue to meet the requirements of Sec.
80.1453(a)(5)(iii).
(f) Any party that uses a renewable fuel in a commercial or
industrial boiler or ocean-going vessel (as defined in Sec. 80.1401),
or designates a renewable fuel for use in a boiler or ocean-going
vessel, must retire any RINs received with that renewable fuel and
report the retired RINs in the applicable reports under Sec. 80.1452.
Any 2009 RINs retired pursuant to Sec. 80.1129(e) may be reinstated by
the retiring party for sale or use to demonstrate compliance with a
2010 RVO.
Sec. 80.1430 Requirements for exporters of renewable fuels.
(a) Any party that owns any amount of renewable fuel, whether in
its neat form or blended with gasoline or diesel, that is exported from
any of the regions described in Sec. 80.1426(a) shall acquire
sufficient RINs to offset all applicable Renewable Volume Obligations
representing the exported renewable fuel.
(b) Renewable Volume Obligations. An exporter of renewable fuel
shall determine its Renewable Volume Obligations from the volumes of
the renewable fuel exported.
(1) For exported volumes of biodiesel (mono-alkyl ester) or non-
ester renewable diesel, a renewable fuel exporter's Renewable Volume
Obligation for biomass-based diesel shall be calculated according to
the following formula:
RVOBBD,i = [Sigma](VOLk *
EVk)i + DBBD,i-1
Where:
RVOBBD,i = The Renewable Volume Obligation for biomass-
based diesel for the exporter for calendar year i, in gallons.
k = A discrete volume of biodiesel (mono-alkyl ester) or non-ester
renewable diesel fuel.
VOLk = The standardized volume of discrete volume k of
exported biodiesel (mono-alkyl ester) or non-ester renewable diesel,
in gallons, calculated in accordance with Sec. 80.1426(d)(10).
EVk = The equivalence value associated with discrete
volume k.
[Sigma] = Sum involving all volumes of biodiesel (mono-alkyl ester)
or non-ester renewable diesel exported.
DBBD,i-1 = Deficit carryover from the previous year for
biomass-based diesel, in gallons.
(2) For exported volumes of all renewable fuels, a renewable fuel
exporter's Renewable Volume Obligation for total renewable fuel shall
be calculated according to the following formula:
RVORF,i = [Sigma](VOLk *
EVk)i + DRF,i-1
Where:
RVORF,i = The Renewable Volume Obligation for renewable
fuel for the exporter for calendar year i, in gallons of renewable
fuel.
k = A discrete volume of renewable fuel.
VOLk = The standardized volume of discrete volume k of
exported renewable fuel, in gallons, calculated in accordance with
Sec. 80.1426(d)(10).
EVk = The equivalence value associated with discrete
volume k.
[Sigma] = Sum involving all volumes of renewable fuel exported.
DRF,i-1 = Deficit carryover from the previous year for
renewable fuel, in gallons.
(3)(i) If the equivalence value for a volume of renewable fuel can
be determined pursuant to Sec. 80.1415 based on its composition, then
the appropriate equivalence value shall be used in the calculation of
the exporter's Renewable Volume Obligations.
(ii) If the equivalence value for a volume of renewable fuel cannot
be determined, the value of EVk shall be 1.0.
(c) Each exporter of renewable fuel must demonstrate compliance
with its RVOs using RINs it has acquired, pursuant to Sec. 80.1427.
Sec. 80.1431 Treatment of invalid RINs.
(a) Invalid RINs. An invalid RIN is a RIN that is any of the
following:
(1) Is a duplicate of a valid RIN.
(2) Was based on volumes that have not been standardized to 60
[deg]F.
(3) Has expired, except as provided in Sec. 80.1428(c).
(4) Was based on an incorrect equivalence value.
(5) Is deemed invalid under Sec. 80.1467(g).
(6) Does not represent renewable fuel as defined in Sec. 80.1401.
(7) Was assigned an incorrect ``D'' code value under Sec.
80.1426(d)(3) for the associated volume of fuel.
[[Page 25125]]
(8) In the event that the same RIN is transferred to two or more
parties, all such RINs are deemed invalid, unless EPA in its sole
discretion determines that some portion of these RINs is valid.
(9) Was otherwise improperly generated.
(b) In the case of RINs that are invalid, the following provisions
apply:
(1) Upon determination by any party that RINs owned are invalid,
the party must adjust its records, reports, and compliance calculations
in which the invalid RINs were used as necessary to reflect the
deletion of the invalid RINs. The party must retire the invalid RINs in
the applicable RIN transaction reports under Sec. 80.1452(c)(2) for
the quarter in which the RINs were determined to be invalid.
(2) Invalid RINs cannot be used to achieve compliance with the
Renewable Volume Obligations of an obligated party or exporter,
regardless of the party's good faith belief that the RINs were valid at
the time they were acquired.
(3) Any valid RINs remaining after deleting invalid RINs must first
be applied to correct the transfer of invalid RINs to another party
before applying the valid RINs to meet the party's Renewable Volume
Obligations at the end of the compliance year.
Sec. 80.1432 Reported spillage or disposal of renewable fuel.
(a) A reported spillage or disposal under this subpart means a
spillage or disposal of renewable fuel associated with a requirement by
a federal, state, or local authority to report the spillage or
disposal.
(b) Except as provided in paragraph (c) of this section, in the
event of a reported spillage or disposal of any volume of renewable
fuel, the owner of the renewable fuel must retire a number of RINs
corresponding to the volume of spilled or disposed of renewable fuel
multiplied by its equivalence value.
(1) If the equivalence value for the spilled or disposed of volume
may be determined pursuant to Sec. 80.1415 based on its composition,
then the appropriate equivalence value shall be used.
(2) If the equivalence value for a spilled or disposed of volume of
renewable fuel cannot be determined, the equivalence value shall be
1.0.
(c) If the owner of a volume of renewable fuel that is spilled or
disposed of and reported establishes that no RINs were generated to
represent the volume, then no RINs shall be retired.
(d) A RIN that is retired under paragraph (b) of this section:
(1) Must be reported as a retired RIN in the applicable reports
under Sec. 80.1452.
(2) May not be transferred to another party or used by any
obligated party to demonstrate compliance with the party's Renewable
Volume Obligations.
Sec. Sec. 80.1433-80.1439 [Reserved]
Sec. 80.1440 What are the provisions for blenders who handle and
blend less than 125,000 gallons of renewable fuel per year?
(a) Renewable fuel blenders who handle and blend less than 125,000
gallons of renewable fuel per year, and who do not have Renewable
Volume Obligations, are permitted to delegate their RIN-related
responsibilities to the party directly upstream of them who supplied
the renewable fuel for blending.
(b) The RIN-related responsibilities that may be delegated directly
upstream include all the following:
(1) The RIN separation requirements of Sec. 80.1429.
(2) The recordkeeping requirements of Sec. 80.1451.
(3) The reporting requirements of Sec. 80.1452.
(4) The attest engagement requirements of Sec. 80.1464.
(c) For upstream delegation of RIN-related responsibilities, both
parties must agree on the delegation, and a quarterly written statement
signed by both parties must be included with the reporting party's
reports under Sec. 80.1452.
(1) If EPA finds that a renewable fuel blender improperly delegated
its RIN-related responsibilities under this subpart M, the blender will
be held accountable for any RINs separated and will be subject to all
RIN-related responsibilities under this subpart.
(2) [Reserved]
(d) Renewable fuel blenders who handle and blend less than 125,000
gallons of renewable fuel per year and who do not opt to delegate their
RIN-related responsibilities will be subject to all requirements stated
in paragraph (b) of this section, and all other applicable requirements
of this subpart M.
Sec. 80.1441 Small refinery exemption.
(a)(1) Transportation fuel produced at a refinery by a refiner, or
foreign refiner (as defined at Sec. 80.1465(a)), is exempt through
December 31, 2010 from the renewable fuel standards of Sec. 80.1405;
and the refinery, or foreign refinery, is exempt from the requirements
that apply to obligated parties under this subpart M if that refinery
meets the definition of a small refinery under Sec. 80.1401 for
calendar year 2006.
(2) This exemption shall apply unless a refiner chooses to waive
this exemption (as described in paragraph (f) of this section), or the
exemption is extended (as described in paragraph (e) of this section).
(3) For the purposes of this section, the term ``refiner'' shall
include foreign refiners.
(4) This exemption shall only apply to refineries that process
crude oil through refinery processing units.
(5) The small refinery exemption is effective immediately, except
as specified in paragraph (b)(3) of this section.
(b)(1) A refiner owning a small refinery must submit a verification
letter to EPA containing all of the following information:
(i) The annual average aggregate daily crude oil throughput for the
period January 1, 2006 through December 31, 2006 (as determined by
dividing the aggregate throughput for the calendar year by the number
365).
(ii) A letter signed by the president, chief operating or chief
executive officer of the company, or his/her designee, stating that the
information contained in the letter is true to the best of his/her
knowledge, and that the refinery was small as of December 31, 2006.
(iii) Name, address, phone number, facsimile number, and e-mail
address of a corporate contact person.
(2) Verification letters must be submitted by January 1, 2010 to
one of the addresses listed in paragraph (h) of this section.
(3) For foreign refiners the small refinery exemption shall be
effective upon approval, by EPA, of a small refinery application. The
application must contain all of the elements required for small
refinery verification letters (as specified in paragraph (b)(1) of this
section), must satisfy the provisions of Sec. 80.1465(f) through (h)
and (o), and must be submitted by January 1, 2010 to one of the
addresses listed in paragraph (h) of this section.
(4) Small refinery verification letters are not required for those
refiners who have already submitted a verification letter under subpart
K of this Part 80.
(c) If EPA finds that a refiner provided false or inaccurate
information regarding a refinery's crude throughput (pursuant to
paragraph (b)(1)(i) of this section) in its small refinery verification
letter, the exemption will be void as of the effective date of these
regulations.
(d) If a refiner is complying on an aggregate basis for multiple
refineries, any such refiner may exclude from the calculation of its
Renewable Volume Obligations (under Sec. 80.1407) transportation fuel
from any refinery
[[Page 25126]]
receiving the small refinery exemption under paragraph (a) of this
section.
(e)(1) The exemption period in paragraph (a) of this section shall
be extended by the Administrator for a period of not less than two
additional years if a study by the Secretary of Energy determines that
compliance with the requirements of this subpart would impose a
disproportionate economic hardship on a small refinery.
(2) A refiner may petition the Administrator for an extension of
its small refinery exemption, based on disproportionate economic
hardship, at any time.
(i) 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 hardship
the refinery would face in producing transportation fuel meeting the
requirements of Sec. 80.1405 and the date the refiner anticipates that
compliance with the requirements can reasonably be achieved at the
small refinery.
(ii) The Administrator shall act on such a petition not later than
90 days after the date of receipt of the petition.
(f) At any time, a refiner with an approved small refinery
exemption under paragraph (a) of this section may waive that exemption
upon notification to EPA.
(1) A refiner's notice to EPA that it intends to waive its small
refinery exemption must be received by November 1 to be effective in
the next compliance year.
(2) The waiver will be effective beginning on January 1 of the
following calendar year, at which point the gasoline produced at that
refinery will be subject to the renewable fuels standard of Sec.
80.1405 and all other requirements that apply to obligated parties
under this Subpart M.
(3) The waiver must be sent to EPA at one of the addresses listed
in paragraph (h) of this section.
(g) A refiner that acquires a refinery from either an approved
small refiner (as defined under Sec. 80.1442(a)) or another refiner
with an approved small refinery exemption under paragraph (a) of this
section shall notify EPA in writing no later than 20 days following the
acquisition.
(h) Verification letters under paragraph (b) of this section,
petitions for small refinery hardship extensions under paragraph (e) of
this section, and small refinery exemption waivers under paragraph (f)
of this section shall be sent to one of the following addresses:
(1) For US mail: U.S. EPA, Attn: RFS2 Program, 6406J, 1200
Pennsylvania Avenue, NW., Washington, DC 20460.
(2) For overnight or courier services: U.S. EPA, Attn: RFS2
Program, 6406J, 1310 L Street, NW, 6th floor, Washington, DC 20005.
(202) 343-9038.
Sec. 80.1442 What are the provisions for small refiners under the RFS
program?
(a)(1) To qualify as a small refiner under this section, a refiner
must meet all of the following criteria:
(i) The refiner produced transportation fuel at its refineries by
processing crude oil through refinery processing units from January 1,
2006 through December 31, 2006.
(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 2006 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 2006.
(2) For the purposes of this section, the term ``refiner'' shall
include foreign refiners.
(b) Applications for small refiner status. (1) Applications for
small refiner status under this section must be submitted to EPA by
January 1, 2010.
(2) Small refiner status applications under this section must
include all 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:
(i) A listing of the name and address of each company location
where any employee worked for the period January 1, 2006 through
December 31, 2006.
(ii) The average number of employees at each location based on the
number of employees for each pay period for the period January 1, 2006
through December 31, 2006.
(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.
(vi) 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, 2006 through
December 31, 2006. 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.
(vii) 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.
(viii) Name, address, phone number, facsimile number, and e-mail
address of a corporate contact person.
(3) In the case of a refiner who acquires or reactivates a refinery
that was shut down or non-operational between January 1, 2005 and
January 1, 2006, the information required in paragraph (b)(2) of this
section must be provided for the time period since the refiner acquired
or reactivated the refinery.
(4) EPA will notify a refiner of its approval or disapproval of the
application for small refiner status by letter.
(5) For foreign refiners the small refiner exemption shall be
effective upon approval, by EPA, of a small refiner application. The
application must contain all of the elements required for small refiner
status applications (as specified in paragraph (b)(2) of this section),
must satisfy the provisions of Sec. 80.1465(f) through (h) and (o),
must demonstrate compliance with the crude oil capacity criterion of
paragraph (a)(1)(iii) of this section, and must be submitted by January
1, 2010 to one of the addresses listed in paragraph (i) of this
section.
(c) Small refiner temporary exemption. (1) Transportation fuel
produced by a refiner, or foreign refiner (as defined at Sec.
80.1465(a)), is exempt through December 31, 2010 from the renewable
fuel standards of Sec. 80.1405 and the requirements that apply to
obligated parties under this subpart if the refiner or foreign refiner
meets all of the following criteria:
(i) The refiner produced transportation fuel at its refineries by
processing crude oil through refinery processing units from January 1,
2006 through December 31, 2006.
(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 2006 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
[[Page 25127]]
equal to 155,000 barrels per calendar day (bpcd) for 2006.
(2) The small refiner exemption shall apply to an approved small
refiner unless that refiner chooses to waive this exemption (as
described in paragraph (d) of this section).
(d)(1) A refiner with approved small refiner status may, at any
time, waive the small refiner exemption under paragraph (c) of this
section upon notification to EPA.
(2) A refiner's notice to EPA that it intends to waive the small
refiner exemption must be received by November 1 of a given year in
order for the waiver to be effective for the following calendar year.
The waiver will be effective beginning on January 1 of the following
calendar year, at which point the refiner will be subject to the
renewable fuel standards of Sec. 80.1405 and the requirements that
apply to obligated parties under this subpart.
(3) The waiver must be sent to EPA at one of the addresses listed
in paragraph (j) of this section.
(e) Refiners who qualify as small refiners under this section and
subsequently fail to meet all of the qualifying criteria as set out in
paragraph (a) of this section are disqualified as small refiners as of
the effective date of this subpart, except as provided under paragraphs
(d) and (e)(2) of this section.
(1) In the event such disqualification occurs, the refiner shall
notify EPA in writing no later than 20 days following the disqualifying
event.
(2) Disqualification under this paragraph (e) shall not apply in
the case of a merger between two approved small refiners.
(f) If EPA finds that a refiner provided false or inaccurate
information in its application for small refiner status under this
subpart M, the refiner will be disqualified as a small refiner as of
the effective date of this subpart.
(g) Any refiner that acquires a refinery from another refiner with
approved small refiner status under paragraph (a) of this section shall
notify EPA in writing no later than 20 days following the acquisition.
(h) Extensions of the small refiner temporary exemption. (1) A
small refiner may apply for an extension of the temporary exemption of
paragraph (c)(1) of this section based on a showing of all the
following:
(i) Circumstances exist that impose disproportionate economic
hardship on the refiner and significantly affect the refiner's ability
to comply with the RFS standards.
(ii) The refiner has made best efforts to comply with the
requirements of this subpart.
(2) A refiner must apply, and be approved, for small refiner status
under this section.
(3) A small refiner's hardship application must include all the
following information:
(i) A plan demonstrating how the refiner will comply with the
requirements of Sec. 80.1405 (and all other requirements of this
subpart applicable to obligated parties), as expeditiously as possible.
(ii) A detailed description of the refinery configuration and
operations including, at a minimum, all the following information:
(A) The refinery's total crude capacity.
(B) Total crude capacity of any other refineries owned by the same
entity.
(C) Total volume of gasoline and diesel produced at the refinery.
(D) Detailed descriptions of efforts to comply.
(E) Bond rating of the entity that owns the refinery.
(F) Estimated investment needed to comply with the requirements of
this subpart.
(4) A small refiner shall notify EPA in writing of any changes to
its situation between approval of the extension application and the end
of its approved extension period.
(5) EPA may impose reasonable conditions on extensions of the
temporary exemption, including reducing the length of such an
extension, if conditions or situations change between approval of the
application and the end of the approved extension period.
(i) Applications for small refiner status, small refiner exemption
waivers, or extensions of the small refiner temporary exemption under
this section must be sent to one of the following addresses:
(1) For US Mail: U.S. EPA, Attn: RFS2 Program, 6406J, 1200
Pennsylvania Avenue, NW., Washington, DC 20460.
(2) For overnight or courier services: U.S. EPA, Attn: RFS2
Program, 6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.
(202) 343-9038.
Sec. 80.1443 What are the opt-in provisions for noncontiguous states
and territories?
(a) Alaska or a United States territory may petition the
Administrator to opt-in to the program requirements of this subpart.
(b) The Administrator will approve the petition if it meets the
provisions of paragraphs (c) and (d) of this section.
(c) The petition must be signed by the Governor of the state or his
authorized representative (or the equivalent official of the
territory).
(d)(1) A petition submitted under this section must be received by
EPA by November 1 for the state or territory to be included in the RFS
program in the next calendar year.
(2) A petition submitted under this section should be sent to
either of the following addresses:
(i) For US Mail: U.S. EPA, Attn: RFS Program, 6406J, 1200
Pennsylvania Avenue, NW., Washington, DC 20460.
(ii) For overnight or courier services: U.S. EPA, Attn: RFS
Program, 6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.
(202) 343-9038.
(e) Upon approval of the petition by the Administrator:
(1) EPA shall calculate the standards for the following year,
including the total gasoline and diesel fuel volume for the state or
territory in question.
(2) Beginning on January 1 of the next calendar year, all gasoline
and diesel fuel refiners and importers in the state or territory for
which a petition has been approved shall be obligated parties as
defined in Sec. 80.1406.
(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. 80.1426(a)(2), be required to
generate RINs and comply with other requirements of this subpart M that
are applicable to producers of renewable fuel.
Sec. 80.1444-80.1448 [Reserved]
Sec. 80.1449 What are the Production Outlook Report requirements?
(a) A renewable fuel producer or importer, for each of its
facilities, must submit all the following information, as applicable,
to EPA annually beginning February 28, 2010:
(1) The type, or types, of renewable fuel expected to be produced
or imported at each facility owned by the renewable fuel producer or
importer.
(2) The volume of each type of renewable fuel expected to be
produced or imported at each facility.
(3) The number of RINs expected to be generated by the renewable
fuel producer or importer for each type of renewable fuel.
(4) Information about all the following:
(i) Existing and planned production capacity.
(ii) Long-range plans.
(iii) Feedstocks and production processes to be used at each
production facility.
(iv) Changes to the facility that would raise or lower emissions of
any greenhouse gases from the facility.
[[Page 25128]]
(5) For expanded production capacity that is planned or underway at
each existing facility, or new production facilities that are planned
or underway, information on all the following:
(i) Strategic planning.
(ii) Planning and front-end engineering.
(iii) Detailed engineering and permitting.
(iv) Procurement and construction.
(v) Commissioning and startup.
(6) Whether capital commitments have been made or are projected to
be made.
(b) The information listed in paragraph (a) of this section shall
include the reporting party's best estimates for the five following
calendar years.
(c) Production outlook reports must provide an update of the
progress in each of the areas listed in paragraph (a)(5) of this
section.
(d) Production outlook reports shall be sent to one of the
following addresses:
(1) For US Mail: U.S. EPA, Attn: RFS2 Program-Production Outlook
Reports, 6406J, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
(2) For overnight or courier services: U.S. EPA, Attn: RFS2
Program-Production Outlook Reports, 6406J, 1310 L Street, NW., 6th
floor, Washington, DC 20005. (202) 343-9038.
Sec. 80.1450 What are the registration requirements under the RFS
program?
(a) Obligated Parties and Exporters. Any obligated party described
in Sec. 80.1406, and any exporter of renewable fuel described in Sec.
80.1430, must provide EPA with the information specified for
registration under Sec. 80.76, if such information has not already
been provided under the provisions of this part. An obligated party or
an exporter of renewable fuel must receive EPA-issued identification
numbers prior to engaging in any transaction involving RINs.
Registration information must be submitted to EPA by January 1, 2010 or
60 days prior to engaging in any transaction involving RINs, whichever
is later.
(b) Producers. Except as provided in Sec. 80.1426(b)(1), any
foreign or domestic producer of renewable fuel, regardless of whether
RINs will be generated for that renewable fuel, must provide EPA the
information specified under Sec. 80.76 if such information has not
already been provided under the provisions of this part, and must
receive EPA-issued company and facility identification numbers prior to
generating or assigning any RINs. All the following registration
information must be submitted to EPA by January 1, 2010 or 60 days
prior to the production of any renewable fuel subject to this subpart,
whichever is later:
(1) A description of the types of renewable fuels and co-products
produced at the facility and all the following for each product type:
(i) A list of the feedstocks capable of being utilized by the
facility.
(ii) A description of the facility's renewable fuel production
processes.
(iii) The facility's renewable fuel production capacity.
(iv) A list of the facility's process energy sources.
(v) For a producer of renewable fuel with a facility that commenced
construction on or before December 19, 2007 per Sec. 80.1403:
(A) The location of the facility.
(B) Record of costs of additions, replacements, and repairs
inclusive of labor costs conducted at the facility since December 19,
2007.
(C) The estimated life of the facility.
(D) A discussion of any economic or technical limitations the
facility may have in using a fuel production pathway that will achieve
a 20 percent reduction in GHG as compared to baseline fuel.
(2) An independent third party engineering review and written
verification of the descriptions made pursuant to paragraph (b)(1) of
this section.
(i) The verifications required under this section must be conducted
by a licensed Professional Engineer who works in the chemical
engineering field and who is licensed by the appropriate state agency.
(ii) To be considered an independent third party under this
paragraph (b)(2):
(A) The third party shall not be operated by the renewable fuel
producer or any subsidiary or employee of the renewable fuel producer.
(B) The third party shall be free from any interest in the
renewable fuel producer's business.
(C) The renewable fuel producer shall be free from any interest in
the third party's business.
(D) Use of a third party that is debarred, suspended, or proposed
for debarment pursuant to the Government-wide Debarment and Suspension
regulations, 40 CFR part 32, or the Debarment, Suspension and
Ineligibility provisions of the Federal Acquisition Regulations, 48
CFR, part 9, subpart 9.4, shall be deemed noncompliance with the
requirements of this section.
(iii) The independent third party shall retain all records
pertaining to the verification required under this section for a period
of five years from the date of creation and shall deliver such records
to the Administrator upon request.
(iv) The renewable fuel producer must retain records of the review
and verification, as required in Sec. 80.1451(b)(7).
(c) Importers. Importers of renewable fuel must provide EPA the
information specified under Sec. 80.76, if such information has not
already been provided under the provisions of this part and must
receive an EPA-issued company identification number prior to owning any
RINs. Registration information may be submitted to EPA by January 1,
2010 or 60 days prior to engaging in any transaction involving RINs,
whichever is later.
(d) Registration updates. Except as provided in Sec.
80.1426(b)(1):
(1) Any producer of renewable fuel who makes changes to his
facility that will qualify his renewable fuel for a renewable fuel
category or D code as defined in Sec. 80.1425(g) that is not reflected
in the producer's registration information on file with EPA must update
his registration information and submit a copy of an updated
independent engineering review at least 60 days prior to producing the
new type of renewable fuel.
(2) Any producer of renewable fuel who makes any other changes to a
facility not affecting the renewable fuel category for which the
producer is registered must update his registration information within
7 days of the change.
(e) Parties who own RINs or who intend to own RINs. Any party who
owns or intends to own RINs, but who is not covered by paragraphs (a),
(b), or (d) of this section, must provide EPA the information specified
under Sec. 80.76, if such information has not already been provided
under the provisions of this part and must receive an EPA-issued
company identification number prior to owning any RINs. Registration
information must be submitted to EPA by January 1, 2010 or 60 days
prior to engaging in any transaction involving RINs, whichever is
later.
(f) Registration shall be on forms, and following policies,
established by the Administrator.
Sec. 80.1451 What are the recordkeeping requirements under the RFS
program?
(a) Beginning January 1, 2010, any obligated party (as described at
Sec. 80.1406) or exporter of renewable fuel (as described at Sec.
80.1430) must keep all of the following records:
(1) Product transfer documents consistent with Sec. 80.1453 and
associated with the obligated party's activity, if any, as transferor
or transferee of renewable fuel.
[[Page 25129]]
(2) Copies of all reports submitted to EPA under Sec. Sec. 80.1449
and 80.1452(a).
(3) Records related to each RIN transaction, including all the
following:
(i) A list of the RINs owned, purchased, sold, retired, or
reinstated.
(ii) The parties involved in each RIN transaction including the
transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(4) Records related to the use of RINs (by facility, if applicable)
for compliance, including all the following:
(i) Methods and variables used to calculate the Renewable Volume
Obligations pursuant to Sec. 80.1407 or Sec. 80.1430.
(ii) List of RINs used to demonstrate compliance.
(iii) Additional information related to details of RIN use for
compliance.
(b) Beginning January 1, 2010, any foreign or domestic producer of
a renewable fuel as defined in Sec. 80.1401 must keep all of the
following records:
(1) Product transfer documents consistent with Sec. 80.1453 and
associated with the renewable fuel producer's activity, if any, as
transferor or transferee of renewable fuel.
(2) Copies of all reports submitted to EPA under Sec. Sec. 80.1449
and 80.1452(b).
(3) Records related to the generation and assignment of RINs for
each facility, including all of the following:
(i) Batch volume in gallons.
(ii) Batch number.
(iii) RIN as assigned under Sec. 80.1426.
(iv) Identification of batches by renewable category.
(v) Date of production.
(vi) Results of any laboratory analysis of batch chemical
composition or physical properties.
(vii) Additional information related to details of RIN generation.
(4) Records related to each RIN transaction, including all of the
following:
(i) A list of the RINs owned, purchased, sold, retired, or
reinstated.
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(5) Records related to the production, importation, ownership, sale
or use of any volume of renewable fuel or blend of renewable fuel and
gasoline or diesel fuel that any party designates for use as
transportation fuel, jet fuel, or home heating oil and the use of the
fuel or blend as transportation fuel, jet fuel, or home heating oil
without further blending, in the designated form.
(6) Documents associated with feedstock purchases and transfers
that identify where the feedstocks were produced and are sufficient to
verify that feedstocks used are renewable biomass (as defined in Sec.
80.1401) if RINs are generated, or sufficient to verify that feedstocks
used are not renewable biomass if no RINs are generated.
(i) Renewable fuel producers who use planted crops or crop residue
from existing agricultural land, or who use planted trees or slash from
actively managed tree plantations must keep records that serve as
evidence that the land from which the feedstock was obtained was
continuously actively managed or fallow, and nonforested, since
December 19, 2007. The records must be provided by the feedstock
producer and consist of at least one of the following documents: Sales
records for planted crops or trees, crop residue, livestock, or slash;
purchasing records for fertilizer, weed control, or reseeding,
including seeds, seedlings, or other nursery stock; a written
management plan for agricultural or silvicultural purposes;
documentation of participation in an agricultural, or silvicultural
program sponsored by a Federal, state or local government agency; or
documentation of land management in accordance with an agricultural or
silvicultural product certification program.
(ii) Renewable fuel producers who use any other type of renewable
biomass must have written certification from their feedstock supplier
that the feedstock qualifies as renewable biomass.
(iii) Renewable fuel producers who do not use renewable biomass
must have written certification from their feedstock supplier that the
feedstock does not qualify as renewable biomass.
(7) Copies of registration documents required under Sec. 80.1450,
including information on fuels and products, feedstocks, facility
production processes and capacity, energy sources, and independent
third party engineering review.
(c) Beginning January 1, 2010, any importer of a renewable fuel (as
defined in Sec. 80.1401) must keep all of the following records:
(1) Product transfer documents consistent with Sec. 80.1453 and
associated with the renewable fuel importer's activity, if any, as
transferor or transferee of renewable fuel.
(2) Copies of all reports submitted to EPA under Sec. Sec. 80.1449
and 80.1452(b); however, duplicate records are not required.
(3) Records related to the generation and assignment of RINs for
each facility, including all of the following:
(i) Batch volume in gallons.
(ii) Batch number.
(iii) RIN as assigned under Sec. 80.1426.
(iv) Identification of batches by renewable category.
(v) Date of import.
(vi) Results of any laboratory analysis of batch chemical
composition or physical properties.
(vii) Additional information related to details of RIN generation.
(4) Records related to each RIN transaction, including all of the
following:
(i) A list of the RINs owned, purchased, sold, retired, or
reinstated.
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(5) Documents associated with feedstock purchases and transfers,
sufficient to verify that feedstocks used are renewable biomass (as
defined in Sec. 80.1401) if the importer generates RINs.
(6) Documents associated with feedstock purchases and transfers,
sufficient to verify that feedstocks used are not renewable biomass as
defined in Sec. 80.1401 if the importer does not generate RINs.
(7) Copies of registration documents required under Sec. 80.1450.
(8) Records related to the import of any volume of renewable fuel
that the importer designates for use as transportation fuel, jet fuel,
or home heating oil.
(d) Beginning January 1, 2010, any production facility with a
baseline volume of fuel that is not subject to the 20% GHG threshold,
pursuant to Sec. 80.1403(a), must keep all of the following:
(1) Detailed engineering plans for the facility.
(2) Federal, State, and local preconstruction approvals and
permitting.
(3) Procurement and construction contracts and agreements.
(4) Records of electricity consumption and energy use.
(5) Records showing costs of additions, replacements, and repairs
inclusive of labor costs conducted at the facility since December 19,
2007.
(6) Records estimating the life of the existing facility.
(e) Beginning January 1, 2010, any party, other than those parties
covered in paragraphs (a) and (b) of this section,
[[Page 25130]]
that owns RINs must keep all of the following records:
(1) Product transfer documents consistent with Sec. 80.1453 and
associated with the party's activity, if any, as transferor or
transferee of renewable fuel.
(2) Copies of all reports submitted to EPA under Sec. 80.1452(c).
(3) Records related to each RIN transaction by renewable fuel
category, including all of the following:
(i) A list of the RINs owned, purchased, sold, retired, or
reinstated.
(ii) The parties involved in each RIN transaction including the
transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(4) Records related to any volume of renewable fuel that the party
designated for use as transportation fuel, jet fuel, or home heating
oil and from which RINs were separated pursuant to Sec. 80.1429(b)(4).
(f) The records required under paragraphs (a) through (c) of this
section and under Sec. 80.1453 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.
(g) The records required under paragraph (d) of this section shall
be kept through calendar year 2022.
(h) On request by EPA, the records required under this section and
under Sec. 80.1453 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.
(i) The records required in paragraphs (b)(6) and (b)(7) of this
section must be provided to the importer of the renewable fuel by any
foreign producer not generating RINs for his renewable fuel.
Sec. 80.1452 What are the reporting requirements under the RFS
program?
(a) Obligated parties and exporters. Any obligated party described
in Sec. 80.1406 or exporter of renewable fuel described in Sec.
80.1430 must submit to EPA reports according to the schedule, and
containing all the information, that is set forth in this paragraph
(a).
(1) Annual compliance demonstration reports for the previous
compliance period shall be submitted on February 28 of each year and
shall include all of the following information:
(i) The obligated party's name.
(ii) The EPA company registration number.
(iii) Whether the party is complying on a corporate (aggregate) or
facility-by-facility basis.
(iv) The EPA facility registration number, if complying on a
facility-by-facility basis.
(v) The production volume of all of the products listed in Sec.
80.1407(c) and (f) for the reporting year.
(vi) The RVOs, as defined in Sec. 80.1427(a) for obligated parties
and Sec. 80.1430(b) for exporters of renewable fuel, for the reporting
year.
(vii) Any deficit RVOs carried over from the previous year.
(viii) The total current-year RINs by type of renewable fuel, as
those fuels are defined in Sec. 80.1401 (i.e., cellulosic biofuel,
biomass-based diesel, advanced biofuels, and renewable fuels), used for
compliance.
(ix) The total prior-year RINs by renewable fuel type, as those
fuels are defined in Sec. 80.1401, used for compliance.
(x) A list of all RINs used for compliance in the reporting year.
(A) For the 2010 reporting year only (January 1--December 31,
2010), a list of all 38-digit RINs used to demonstrate compliance.
(B) Starting January 1, 2011, RINs used to meet compliance will be
conveyed via the EPA Moderated Transaction System (EMTS) as set forth
in paragraph (e) of this section.
(xi) Any deficit RVO(s) carried into the subsequent year.
(xii) Any additional information that the Administrator may
require.
(2) The RIN transaction reports required under paragraph (c)(1) of
this section.
(3) The quarterly RIN activity reports required under paragraph
(c)(2) of this section.
(4) Reports required under this paragraph (a) must be signed and
certified as meeting all the applicable requirements of this subpart by
the owner or a responsible corporate officer of the obligated party.
(b) Renewable fuel producers (domestic and foreign) and importers.
Any domestic producer or importer of renewable fuel, or foreign
renewable fuel producer who generates RINs, must submit to EPA reports
according to the schedule, and containing all the information, that is
set forth in this paragraph (b).
(1)(i) Until December 31, 2010, renewable fuel production reports
for each facility owned by the renewable fuel producer or importer
shall be submitted monthly, according to the schedule specified in
paragraph (d)(1) of this section.
(ii) Starting January 1, 2011, renewable fuel production reports
for each facility owned by the renewable fuel producer or importer
shall be submitted in accordance with paragraph (e)(2) of this section.
(iii) The renewable fuel production reports shall include all the
following information for each batch of renewable fuel produced, where
``batch'' means a discrete quantity of renewable fuel produced and
either assigned or not assigned a unique batch-RIN per Sec.
80.1426(b)(2):
(A) The renewable fuel producer's name.
(B) The EPA company registration number.
(C) The EPA facility registration number.
(D) The applicable monthly reporting period.
(E) Whether RINs were generated for each batch according to Sec.
80.1426.
(F) The production date of each batch.
(G) The type of renewable fuel of each batch, as defined in Sec.
80.1401.
(H) Information related to the volume of denaturant and applicable
equivalence value of each batch.
(I) The volume of each batch produced.
(J) The process(es) and feedstock(s) used and proportion of
renewable volume attributable to each process and feedstock.
(K) The type and volume of co-products produced with each batch of
renewable fuel.
(L) In the case that RINs were generated for the batch, a list of
the RINs generated and a certification that the feedstock(s) used for
each batch meets the definition of renewable biomass as defined in
Sec. 80.1401.
(M) In the case that RINs were not generated for the batch, an
explanation as to the reason for not generating RINs.
(N) Any additional information the Administrator may require.
(2) The RIN transaction reports required under paragraph (c)(1) of
this section.
(3) The quarterly RIN activity reports required under paragraph
(c)(2) of this section.
(4) Reports required under this paragraph (b) must be signed and
certified as meeting all the applicable requirements of this subpart by
the owner or a responsible corporate officer of the renewable fuel
producer.
(c) All RIN-owning parties. Any party, including any party
specified in paragraphs (a) and (b) of this section, that owns RINs
during a reporting period, must submit reports to EPA
[[Page 25131]]
according to the schedule, and containing all the information, that is
set forth in this paragraph (c).
(1)(i) Until December 31, 2010, RIN transaction reports listing
each RIN transaction shall be submitted monthly according to the
schedule in paragraph (d)(1) of this section.
(ii) Starting January 1, 2011, RIN transaction reports listing each
RIN transaction shall be submitted in accordance with paragraph (e)(3)
of this section.
(iii) Each report required by paragraph (c)(1)(i) of this section
shall include all of the following information:
(A) The submitting party's name.
(B) The party's EPA company registration number.
(C) [Reserved]
(D) The applicable monthly reporting period.
(E) Transaction type (i.e., RIN purchase, RIN sale, retired RIN,
reinstated 2009 RIN).
(F) Transaction date.
(G) For a RIN purchase or sale, the trading partner's name.
(H) For a RIN purchase or sale, the trading partner's EPA company
registration number. For all other transactions, the submitting party's
EPA company registration number.
(I) RIN subject to the transaction.
(J) For a RIN purchase or sale, the per gallon RIN price and/or the
per gallon renewable price if the RIN price is included.
(K) For a retired RIN, the reason for retiring the RIN (e.g.,
invalid RIN under Sec. 80.1431, reportable spill under Sec. 80.1432,
foreign producer volume correction under Sec. 80.1466(e), renewable
fuel used in a boiler or ocean-going vessel under Sec. 80.1429(f),
enforcement obligation, or use for compliance (per paragraph (a)(1)(x)
of this section), etc.).
(L) Any additional information that the Administrator may require.
(2) Quarterly RIN activity reports shall be submitted to EPA
according to the schedule specified in paragraph (d)(2) of this
section. Each report shall summarize RIN activities for the reporting
period, separately for RINs separated from a renewable fuel volume and
the sum of both RINs assigned to a renewable fuel volume and RINs
generated, but not assigned to a renewable fuel volume. The quarterly
RIN activity reports shall include all of the following information:
(i) The submitting party's name.
(ii) The party's EPA company registration number.
(iii) The number of current-year RINs owned at the start of the
month.
(iv) The number of prior-year RINs owned at the start of the month.
(v) The total current-year RINs purchased.
(vi) The total prior-year RINs purchased.
(vii) The total current-year RINs sold.
(viii) The total prior-year RINs sold.
(ix) The total current-year RINs retired.
(x) The total prior-year RINs retired.
(xi) The number of current-year RINs owned at the end of the
quarter.
(xii) The number of prior-year RINs owned at the end of the
quarter.
(xiii) For parties reporting RIN activity under this paragraph for
RINs generated, but not assigned to a renewable fuel volume and/or RINs
assigned to a volume of renewable fuel, and the volume of renewable
fuel (in gallons) owned at the end of the quarter.
(xiv) The total 2009 retired RINs reinstated.
(xv) Any additional information that the Administrator may require.
(3) All reports required under this paragraph (c) must be signed
and certified as meeting all the applicable requirements of this
subpart by the RIN owner or a responsible corporate officer of the RIN
owner.
(d) Report submission deadlines. The submission deadlines for
monthly and quarterly reports shall be as follows:
(1) Monthly reports shall be submitted to EPA by the last day of
the next calendar month following the compliance period (i.e., the
report covering January would be due by February 28th, the report
covering February would be due by March 31st, etc.).
(2) Quarterly reports shall be submitted to EPA by the last day of
the second month following the compliance period (i.e., the report
covering January-March would be due by May 31st, the report covering
April-June would be due by August 31st, the report covering July-
September would be due by November 30th and the report covering
October-December would be due by February 28th).
(e) EPA Moderated Transaction System (EMTS). (1) Each party
required to report under this section must establish an account with
EMTS by October 1, 2010 or sixty (60) days prior to engaging in any
transaction involving RINs, whichever is later.
(2) Starting January 1, 2011, each time a domestic producer or
importer of renewable fuel, or foreign renewable fuel producer who
generates RINs, produces or imports a batch of renewable fuel, all the
following information must be submitted to EPA within three (3)
business days:
(i) The renewable fuel producer's or importer's name.
(ii) The EPA company registration number.
(iii) The EPA facility registration number.
(iv) Whether RINs were generated for the batch, according to Sec.
80.1426.
(v) The production date of the batch.
(vi) The type of renewable fuel of the batch, as defined in Sec.
80.1401.
(vii) Information related to the volume of denaturant and
applicable equivalence value of each batch.
(viii) The volume of the batch.
(ix) The process(es) and feedstock(s) used and proportion of
renewable volume attributable to each process and feedstock.
(x) A certification that the feedstock(s) used for each batch meets
the definition of renewable biomass as defined in Sec. 80.1401.
(xi) The type and volume of co-products produced with the batch of
renewable fuel.
(xii) In the case that RINs were generated for the batch, a list of
the RINs generated and a certification that the feedstock(s) used for
each batch meets the definition of renewable biomass as defined in
Sec. 80.1401.
(xiii) In the case that RINs were not generated for the batch, an
explanation as to the reason for not generating RINs.
(xiv) Any additional information the Administrator may require.
(3) Starting January 1, 2011, each time any party engages in a
transaction involving RINs, all the following information must be
submitted to EPA within three (3) business days:
(i) The submitting party's name.
(ii) The party's EPA company registration number.
(iii) [Reserved]
(iv) The applicable monthly reporting period.
(v) Transaction type (i.e., RIN purchase, RIN sale, retired RIN).
(vi) Transaction date.
(vii) For a RIN purchase or sale, the trading partner's name.
(viii) For a RIN purchase or sale, the trading partner's EPA
company registration number. For all other transactions, the submitting
party's EPA company registration number.
(ix) RIN subject to the transaction.
(x) For a RIN purchase or sale, the per gallon RIN price and/or the
per gallon renewable price if the RIN price is included.
(xi) For a retired RIN, the reason for retiring the RIN (e.g.,
reportable spill under Sec. 80.1432, foreign producer volume
correction under Sec. 80.1466(e), renewable fuel used in a boiler or
ocean-going vessel under Sec. 80.1429(f), enforcement obligation, or
use for compliance (per paragraph (a)(1)(x) of this section), etc.).
[[Page 25132]]
(xii) Any additional information that the Administrator may
require.
(f) All reports required under this section shall be submitted on
forms and following procedures prescribed by the Administrator.
Sec. 80.1453 What are the product transfer document (PTD)
requirements for the RFS program?
(a) On each occasion when any party transfers ownership of
renewable fuels subject to this subpart, the transferor must provide to
the transferee documents identifying the renewable fuel and any
assigned RINs which include all of the following information, as
applicable:
(1) The name and address of the transferor and transferee.
(2) The transferor's and transferee's EPA company registration
number.
(3) The volume of renewable fuel that is being transferred.
(4) The date of the transfer.
(5) Whether any RINs are assigned to the volume, as follows:
(i) If the assigned RINs are being transferred on the same PTD used
to transfer ownership of the renewable fuel, then the assigned RINs
shall be listed on the PTD.
(ii) If the assigned RINs are being transferred on a separate PTD
from that which is used to transfer ownership of the renewable fuel,
then the PTD which is used to transfer ownership of the renewable fuel
shall state the number of gallon-RINs being transferred as well as a
unique reference to the PTD which is transferring the assigned RINs.
(iii) If no assigned RINs are being transferred with the renewable
fuel, the PTD which is used to transfer ownership of the renewable fuel
shall state ``No assigned RINs transferred''.
(iv) If RINs have been separated from the renewable fuel or blend
pursuant to Sec. 80.1129(b)(4), then all PTDs which are at any time
used to transfer ownership of the renewable fuel or blend shall state,
``This volume of fuel must be used in the designated form, without
further blending.''.
(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.
(c) The RIN number required under paragraph (a)(5) of this section
must always appear in its entirety.
(d) If a RIN is traded in the EPA-Moderated Trading System (EMTS)
as described in Sec. 80.1452(e), the transferor must provide to the
transferee documents that include all information as described in
paragraphs (a) and (b) of this section and the number of RINs
transferred identified by all the following:
(1) Assignment (Assigned or Separated).
(2) Type and/or D code (cellulosic biofuel D=1, biomass-based
diesel D=2, advanced biofuel D=3, renewable fuel D=4).
(3) RIN generation year.
Sec. 80.1454 What are the provisions for renewable fuel production
facilities 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. Except as stated in paragraph (b) of this
section, such production facilities and importers that do not generate
and/or assign RINs to batches of renewable fuel are also exempt from
all the following requirements of this subpart:
(1) The recordkeeping requirements of Sec. 80.1451.
(2) The reporting requirements of Sec. 80.1452.
(3) The attest engagement requirements of Sec. 80.1464.
(4) The production outlook report requirements of Sec. 80.1449.
(b)(1) Renewable fuel production facilities 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. 80.1449 through 80.1452, and
80.1464.
(2) Renewable fuel production facilities and importers who produce
or import less than 10,000 gallons of renewable fuel each year but wish
to own RINs will be subject to all requirements stated in paragraphs
(a)(1) through (a)(4) of this section, and all other applicable
requirements of this subpart M.
Sec. 80.1455 What are the provisions for cellulosic biofuel
allowances?
(a) If EPA reduces the applicable volume of cellulosic biofuel
pursuant to section 211(o)(7)(D)(i) of the Clean Air Act (42 U.S.C.
7545(o)(7)(D)(i)) for any given compliance year, then EPA will provide
cellulosic biofuel allowances for purchase for that compliance year.
(1) The price of these allowances will be set by EPA on an annual
basis in accordance with paragraph (d) of this section.
(2) The total allowances available will be equal to the reduced
cellulosic biofuel volume established by EPA for the compliance year.
(b) Use of allowances. (1) Allowances are only valid for use in the
compliance year that they are made available.
(2) Allowances are nonrefundable.
(3) Allowances are nontransferable except if forfeiting the
allowances to EPA.
(c) Purchase of allowances. (1) Only parties with an RVO for
cellulosic biofuel may purchase cellulosic biofuel allowances.
(2) Allowances shall be purchased from EPA at the time that a party
submits its annual compliance report to EPA pursuant to Sec.
80.1452(a)(1).
(3) Parties may not purchase more allowances than their cellulosic
biofuel RVO minus cellulosic biofuel RINs with a D code of 1 that they
own.
(4) Allowances may be used to meet an obligated party's RVOs for
the advanced biofuel and total renewable fuel standards.
(d) Setting the price of allowances. (1) The price for allowances
shall be set equal to the greater of:
(i) $0.25 per allowance, adjusted for inflation in comparison to
calendar year 2008; or
(ii) $3.00 less the wholesale price of gasoline per allowance,
adjusted for inflation in comparison to calendar year 2008.
(2) The wholesale price of gasoline will be calculated by averaging
the most recent twelve monthly values for U.S. Total Gasoline Bulk
Sales (Price) by All Sellers as provided by the Energy Information
Administration that are available as of September 30 of the year
preceding the compliance period.
(3) The inflation adjustment will be calculated by comparing the
most recent Consumer Price Index for All Urban Consumers (CPI-U) for
All Items expenditure category as provided by the Bureau of Labor
Statistics that is available as of September 30 of the year preceding
the compliance period to the most recent comparable value reported
prior to December 31, 2008. When EPA must set the price of allowances
for a compliance year, EPA will calculate the new amounts for
paragraphs (d)(1)(i) and (ii) of this section for each year after 2008
and every month where data is available for the year preceding the
compliance period.
(e) Cellulosic biofuel allowances under this section will only be
able to be purchased on forms and following procedures prescribed by
EPA.
[[Page 25133]]
Sec. Sec. 80.1456-80.1459 [Reserved]
Sec. 80.1460 What acts are prohibited under the RFS program?
(a) Renewable fuels producer or importer violation. Except as
provided in Sec. 80.1454, no party shall produce or import a renewable
fuel without assigning the proper number of gallon-RINs or identifying
it by a batch-RIN as required under Sec. 80.1426.
(b) RIN generation and transfer violations. No party shall do any
of the following:
(1) Generate a RIN for a fuel that is not a renewable fuel, or for
which the applicable renewable fuel volume was not produced.
(2) Create or transfer to any party a RIN that is invalid under
Sec. 80.1431.
(3) Transfer to any party a RIN that is not properly identified as
required under Sec. 80.1425.
(4) Transfer to any party a RIN with a K code of 1 without
transferring an appropriate volume of renewable fuel to the same party
on the same day.
(5) Introduce into commerce any renewable fuel produced from a
feedstock or through a process that is not described in the party's
registration information.
(c) RIN use violations. No party shall do any of the following:
(1) Fail to acquire sufficient RINs, or use invalid RINs, to meet
the party's RVOs under Sec. 80.1427.
(2) Fail to acquire sufficient RINs to meet the party's RVOs under
Sec. 80.1430.
(3) Use a validly generated RIN to meet the party's RVOs under
Sec. 80.1427, or separate and transfer a validly generated RIN, where
the party ultimately uses the renewable fuel volume associated with the
RIN in an application other than for use as transportation fuel (as
defined in Sec. 80.1401).
(d) RIN retention violation. No party shall retain RINs in
violation of the requirements in Sec. 80.1428(a)(5).
(e) Causing a violation. No party shall cause another party to
commit an act in violation of any prohibited act under this section.
(f) Failure to meet a requirement. No party shall fail to meet any
requirement that applies to that party under this subpart.
Sec. 80.1461 Who is liable for violations under the RFS program?
(a) Parties liable for violations of prohibited acts. (1) Any party
who violates a prohibition under Sec. 80.1460(a) through (d) is liable
for the violation of that prohibition.
(2) Any party who causes another person to violate a prohibition
under Sec. 80.1460(a) through (d) is liable for a violation of Sec.
80.1460(e).
(b) Parties liable for failure to meet other provisions of this
subpart. (1) Any party who fails to meet a requirement of any provision
of this subpart is liable for a violation of that provision.
(2) Any party who causes another party 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. 80.1462 [Reserved]
Sec. 80.1463 What penalties apply under the RFS program?
(a) Any party who is liable for a violation under Sec. 80.1461 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.
(b) Any party liable under Sec. 80.1461(a) for a violation of
Sec. 80.1460(c) for failure to meet its RVOs, or Sec. 80.1460(e) for
causing another party to fail to meet their RVOs, during any averaging
period, is subject to a separate day of violation for each day in the
averaging period.
(c) Any party liable under Sec. 80.1461(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. 80.1464 What are the attest engagement requirements under the
RFS program?
The requirements regarding annual attest engagements in Sec. Sec.
80.125 through 80.127, and 80.130, also apply to any attest engagement
procedures required under this subpart M. In addition to any other
applicable attest engagement procedures, such as the requirements in
Sec. 80.1465, the following annual attest engagement procedures are
required under this subpart.
(a) Obligated parties and exporters. The following attest
procedures shall be completed for any obligated party as stated in
Sec. 80.1406(a) or exporter of renewable fuel that is subject to the
renewable fuel standard under Sec. 80.1405:
(1) Annual compliance demonstration report. (i) Obtain and read a
copy of the annual compliance demonstration report required under Sec.
80.1452(a)(1) which contains information regarding all the following:
(A) The obligated party's volume of finished gasoline, reformulated
gasoline blendstock for oxygenate blending (RBOB), and conventional
gasoline blendstock that becomes finished conventional gasoline upon
the addition of oxygenate (CBOB) produced or imported during the
reporting year.
(B) RVOs.
(C) RINs used for compliance.
(ii) Obtain documentation of any volumes of renewable fuel used in
gasoline at the refinery or import facility or exported during the
reporting year; compute and report as a finding the total volumes of
renewable fuel represented in these documents.
(iii) Compare the volumes of gasoline reported to EPA in the report
required under Sec. 80.1452(a)(1) with the volumes, excluding any
renewable fuel volumes, contained in the inventory reconciliation
analysis under Sec. 80.133, and verify that the volumes reported to
EPA agree with the volumes in the inventory reconciliation analysis.
(iv) Compute and report as a finding the obligated party's or
exporter's RVOs, and any deficit RVOs carried over from the previous
year or carried into the subsequent year, and verify that the values
agree with the values reported to EPA.
(v) Obtain the database, spreadsheet, or other documentation for
all RINs used for compliance during the year being reviewed; calculate
the total number of RINs used for compliance by year of generation
represented in these documents; state whether this information agrees
with the report to EPA and report as a finding any exceptions.
(2) RIN transaction reports. (i) Obtain and read copies of a
representative sample, selected in accordance with the guidelines in
Sec. 80.127, of each RIN transaction type (RINs purchased, RINs sold,
RINs retired, RINs reinstated) included in the RIN transaction reports
required under Sec. 80.1452(a)(2) for the compliance year.
(ii) Obtain contracts, invoices, or other documentation for the
representative samples of RIN transactions; compute the transaction
types, transaction dates, and RINs traded; state whether the
information agrees with the party's reports to EPA and report as a
finding any exceptions.
(3) RIN activity reports. (i) Obtain and read copies of all
quarterly RIN activity reports required under Sec. 80.1452(a)(3) for
the compliance year.
[[Page 25134]]
(ii) Obtain the database, spreadsheet, or other documentation used
to generate the information in the RIN activity reports; compare the
RIN transaction samples reviewed under paragraph (a)(2) of this section
with the corresponding entries in the database or spreadsheet and
report as a finding any discrepancies; compute the total number of
current-year and prior-year RINs owned at the start and end of the
quarter, purchased, sold, retired, and reinstated, and for parties that
reported RIN activity for RINs assigned to a volume of renewable fuel,
the volume of renewable fuel owned at the end of the quarter; as
represented in these documents; and state whether this information
agrees with the party's reports to EPA.
(b) Renewable fuel producers and RIN-generating importers. The
following attest procedures shall be completed for any renewable fuel
producer or RIN-generating importer:
(1) Renewable fuel production reports. (i) Obtain and read copies
of the renewable fuel production reports required under Sec. Sec.
80.1452(b)(1) and (e)(2) for the compliance year.
(ii) Obtain production data for each renewable fuel batch produced
or imported during the year being reviewed; compute the RIN numbers,
production dates, types, volumes of denaturant and applicable
equivalence values, and production volumes for each batch; state
whether this information agrees with the party's reports to EPA and
report as a finding any exceptions.
(iii) Verify that the proper number of RINs were generated and
assigned for each batch of renewable fuel produced or imported, as
required under Sec. 80.1426.
(iv) Obtain product transfer documents for a representative sample,
selected in accordance with the guidelines in Sec. 80.127, of
renewable fuel batches produced or imported during the year being
reviewed; verify that the product transfer documents contain the
applicable information required under Sec. 80.1453; verify the
accuracy of the information contained in the product transfer
documents; report as a finding any product transfer document that does
not contain the applicable information required under Sec. 80.1453.
(v) Obtain documentation, as required under Sec. 80.1451(b)(6),
associated with feedstock purchases and transfers for a representative
sample, selected in accordance with the guidelines in Sec. 80.127, of
renewable fuel batches produced or imported during the year being
reviewed.
(A) If RINs were generated for a given batch of renewable fuel,
verify that feedstocks used meet the definition of renewable biomass in
Sec. 80.1401.
(B) If no RINs were generated for a given batch of renewable fuel,
verify that feedstocks used do not meet the definition of renewable
biomass in Sec. 80.1401 or that there was another reason that the fuel
produced without RINs was not renewable fuel.
(2) RIN transaction reports. (i) Obtain and read copies of a
representative sample, selected in accordance with the guidelines in
Sec. 80.127, of each transaction type (RINs purchased, RINs sold, RINs
retired, RINs reinstated) included in the RIN transaction reports
required under Sec. 80.1452(b)(2) for the compliance year.
(ii) Obtain contracts, invoices, or other documentation for the
representative samples of RIN transactions; compute the transaction
types, transaction dates, and the RINs traded; state whether this
information agrees with the party's reports to EPA and report as a
finding any exceptions.
(3) RIN activity reports. (i) Obtain and read copies of the
quarterly RIN activity reports required under Sec. 80.1452(b)(3) for
the compliance year.
(ii) Obtain the database, spreadsheet, or other documentation used
to generate the information in the RIN activity reports; compare the
RIN transaction samples reviewed under paragraph (b)(2) of this section
with the corresponding entries in the database or spreadsheet and
report as a finding any discrepancies; compute the total number of
current-year and prior-year RINs owned at the start and end of the
quarter, purchased, sold, retired, and reinstated, and for parties that
reported RIN activity for RINs assigned to a volume of renewable fuel,
the volume of renewable fuel owned at the end of the quarter, as
represented in these documents; and state whether this information
agrees with the party's reports to EPA.
(4) Independent Third Party Engineering Review. (i) Obtain
documentation of independent third party engineering review required
under Sec. 80.1450(b)(2).
(ii) Review and verify the written verification and records
generated as part of the independent third party engineering review.
(c) Other parties owning RINs. The following attest procedures
shall be completed for any party other than an obligated party or
renewable fuel producer or importer that owns any RINs during a
calendar year:
(1) RIN transaction reports. (i) Obtain and read copies of a
representative sample, selected in accordance with the guidelines in
Sec. 80.127, of each RIN transaction type (RINs purchased, RINs sold,
RINs retired, RINs reinstated) included in the RIN transaction reports
required under Sec. 80.1452(c)(1) for the compliance year.
(ii) Obtain contracts, invoices, or other documentation for the
representative samples of RIN transactions; compute the transaction
types, transaction dates, and the RINs traded; state whether this
information agrees with the party's reports to EPA and report as a
finding any exceptions.
(2) RIN activity reports. (i) Obtain and read copies of the
quarterly RIN activity reports required under Sec. 80.1452(c)(2) for
the compliance year.
(ii) Obtain the database, spreadsheet, or other documentation used
to generate the information in the RIN activity reports; compare the
RIN transaction samples reviewed under paragraph (c)(1) of this section
with the corresponding entries in the database or spreadsheet and
report as a finding any discrepancies; compute the total number of
current-year and prior-year RINs owned at the start and end of the
quarter, purchased, sold, retired, and reinstated, and for parties that
reported RIN activity for RINs assigned to a volume of renewable fuel,
the volume of renewable fuel owned at the end of the quarter, as
represented in these documents; and state whether this information
agrees with the party's reports to EPA.
(d) The following submission dates apply to the attest engagements
required under this section:
(1) For each compliance year, each party subject to the attest
engagement requirements under this section shall cause the reports
required under this section to be submitted to EPA by May 31 of the
year following the compliance year.
(2) [Reserved]
(e) The party conducting the procedures under this section shall
obtain a written representation from a company representative that the
copies of the reports required under this section are complete and
accurate copies of the reports filed with EPA.
(f) The party conducting the procedures under this section shall
identify and report as a finding the commercial computer program used
by the party to track the data required by the regulations in this
subpart, if any.
[[Page 25135]]
Sec. 80.1465 What are the additional requirements under this subpart
for foreign small refiners, foreign small refineries, and importers of
RFS-FRFUEL?
(a) Definitions. The following additional definitions apply for
this subpart:
(1) Foreign refinery is a refinery that is located outside the
United States, the Commonwealth of Puerto Rico, the U.S. Virgin
Islands, Guam, American Samoa, and the Commonwealth of the Northern
Mariana Islands (collectively referred to in this section as ``the
United States'').
(2) Foreign refiner is a party that meets the definition of refiner
under Sec. 80.2(i) for a foreign refinery.
(3) Foreign small refiner is a foreign refiner that has received a
small refinery exemption under Sec. 80.1441 for one or more of its
refineries or a foreign refiner that has received a small refiner
exemption under Sec. 80.1442.
(4) RFS-FRFUEL is transportation fuel produced at a foreign
refinery that has received a small refinery exemption under Sec.
80.1441 or by a foreign refiner with a small refiner exemption under
Sec. 80.1442.
(5) Non-RFS-FRFUEL is one of the following:
(i) Transportation fuel produced at a foreign refinery that has
received a small refinery exemption under Sec. 80.1441 or by a foreign
refiner with a small refiner exemption under Sec. 80.1442.
(ii) Transportation fuel produced at a foreign refinery that has
not received a small refinery exemption under Sec. 80.1441 or by a
foreign refiner that has not received a small refiner exemption under
Sec. 80.1442.
(b) General requirements for RFS-FRFUEL for foreign small
refineries and small refiners. A foreign refiner must do all the
following:
(1) Designate, at the time of production, each batch of
transportation fuel produced at the foreign refinery that is exported
for use in the United States as RFS-FRFUEL.
(2) Meet all requirements that apply to refiners who have received
a small refinery or small refiner exemption under this subpart.
(c) Designation, foreign small refiner certification, and product
transfer documents.
(1) Any foreign small refiner must designate each batch of RFS-
FRFUEL as such at the time the transportation fuel is produced.
(2) On each occasion when RFS-FRFUEL is loaded onto a vessel or
other transportation mode for transport to the United States, the
foreign small refiner shall prepare a certification for each batch of
RFS-FRFUEL that meets all the following requirements:
(i) The certification shall include the report of the independent
third party under paragraph (d) of this section, and all the following
additional information:
(A) The name and EPA registration number of the refinery that
produced the RFS-FRFUEL.
(B) [Reserved]
(ii) The identification of the transportation fuel as RFS-FRFUEL.
(iii) The volume of RFS-FRFUEL being transported, in gallons.
(3) On each occasion when any party transfers custody or title to
any RFS-FRFUEL prior to its being imported into the United States, it
must include all the following information as part of the product
transfer document information:
(i) Designation of the transportation fuel as RFS-FRFUEL.
(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-FRFUEL is loaded onto a vessel for transport
to the United States the foreign small refiner shall have an
independent third party do all the following:
(i) Inspect the vessel prior to loading and determine the volume of
any tank bottoms.
(ii) Determine the volume of RFS-FRFUEL 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-FRFUEL to the United States.
(v) Determine the date and time the vessel departs the port serving
the foreign refinery.
(vi) Review original documents that reflect movement and storage of
the RFS-FRFUEL from the foreign refinery to the load port, and from
this review determine:
(A) The refinery at which the RFS-FRFUEL was produced; and
(B) That the RFS-FRFUEL remained segregated from Non-RFS-FRFUEL and
other RFS-FRFUEL produced at a different refinery.
(2) The independent third party shall submit a report to all the
following:
(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.
(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 transportation fuel was produced, assurance that
the transportation fuel remained segregated as specified in paragraph
(j)(1) of this section, and a description of the transportation fuel's
movement and storage between production at the source refinery and
vessel loading.
(3) The independent third party must do all the following:
(i) Be approved in advance by EPA, based on a demonstration of
ability to perform the procedures required in this paragraph (d).
(ii) Be independent under the criteria specified in Sec.
80.65(f)(2)(iii).
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities, facilities,
and documents relevant to compliance with the requirements of this
paragraph (d).
(e) Comparison of load port and port of entry testing. (1)(i) Any
foreign small refiner or foreign small refinery and any United States
importer of RFS-FRFUEL shall compare the results from the load port
testing under paragraph (d) of this section, with the port of entry
testing as reported under paragraph (k) of this section, for the volume
of transportation fuel, except as specified in paragraph (e)(1)(ii) of
this section.
(ii) Where a vessel transporting RFS-FRFUEL off loads this
transportation fuel 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 transportation fuel or blendstock between the first United States
port of entry and the subsequent port of entry.
(2) If the temperature-corrected volumes determined at the port of
entry and at the load port differ by more than one percent, the United
States importer and the foreign small refiner or foreign small refinery
shall not treat the transportation fuel as RFS-FRFUEL and the importer
shall include the volume of transportation fuel in 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
[[Page 25136]]
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) Transportation fuel is produced;
(B) Documents related to refinery operations are kept; and
(C) RFS-FRFUEL is stored or transported between the foreign
refinery and the United States, including storage tanks, vessels and
pipelines.
(iii) Inspections and audits may be by EPA employees or contractors
to EPA.
(iv) Any documents requested that are related to matters covered by
inspections and audits must be provided to an EPA inspector or auditor
on request.
(v) Inspections and audits by EPA may include review and copying of
any documents related to all the following:
(A) The volume of RFS-FRFUEL.
(B) The proper classification of transportation fuel as being RFS-
FRFUEL or as not being RFS-FRFUEL.
(C) Transfers of title or custody to RFS-FRFUEL.
(D) Testing of RFS-FRFUEL.
(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.
(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 transportation fuel 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-FRFUEL produced at a foreign refinery is
stored or transported by another company between the refinery and the
vessel that transports the RFS-FRFUEL 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 transportation fuel to the United States under such
exemption, the foreign refiner, and its agents and employees, without
exception, become subject to the full operation of the administrative
and judicial enforcement powers and provisions of the United States
without limitation based on sovereign immunity, with respect to actions
instituted against the foreign refiner, its agents and employees in any
court or other tribunal in the United States for conduct that violates
the requirements applicable to the foreign refiner under this subpart,
including conduct that violates the False Statements Accountability Act
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42
U.S.C. 7413).
(h) Bond posting. Any foreign refiner shall meet the requirements
of this paragraph (h) as a condition to approval of a small foreign
refinery or small foreign refiner exemption under this subpart.
(1) The foreign refiner shall post a bond of the amount calculated
using the following equation:
Bond = G * $ 0.01
Where:
Bond = amount of the bond in United States dollars.
G = the largest volume of transportation fuel 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 or refiner'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 transportation fuel
[[Page 25137]]
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, or shall include an English
language translation.
(j) Prohibitions. (1) No party may combine RFS-FRFUEL with any Non-
RFS-FRFUEL, and no party may combine RFS-FRFUEL with any RFS-FRFUEL
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 party may cause another party 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-FRFUEL shall meet the following requirements:
(1) Each batch of imported RFS-FRFUEL shall be classified by the
importer as being RFS-FRFUEL.
(2) Transportation fuel shall be classified as RFS-FRFUEL 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 transportation fuel batch classified as RFS-FRFUEL,
any United States importer shall have an independent third party do all
the following:
(i) Determine the volume of transportation fuel in the vessel.
(ii) Use the foreign refiner's RFS-FRFUEL certification to
determine the name and EPA-assigned registration number of the foreign
refinery that produced the RFS-FRFUEL.
(iii) Determine the name and country of registration of the vessel
used to transport the RFS-FRFUEL to the United States.
(iv) Determine the date and time the vessel arrives at the United
States port of entry.
(4) Any importer shall submit reports within 30 days following the
date any vessel transporting RFS-FRFUEL 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 transportation fuel that is not
classified as RFS-FRFUEL under paragraph (k)(2) of this section.
(l) Truck imports of RFS-FRFUEL produced at a foreign refinery. (1)
Any refiner whose RFS-FRFUEL is transported into the United States by
truck may petition EPA to use alternative procedures to meet all the
following requirements:
(i) Certification under paragraph (c)(2) of this section.
(ii) Load port and port of entry testing requirements under
paragraphs (d) and (e) of this section.
(iii) Importer testing requirements under paragraph (k)(3) of this
section.
(2) These alternative procedures must ensure RFS-FRFUEL remains
segregated from Non-RFS-FRFUEL until it is imported into the United
States. The petition will be evaluated based on whether it adequately
addresses all the following:
(i) Provisions for monitoring pipeline shipments, if applicable,
from the refinery, that ensure segregation of RFS-FRFUEL from that
refinery from all other transportation fuel.
(ii) Contracts with any terminals and/or pipelines that receive
and/or transport RFS-FRFUEL that prohibit the commingling of RFS-FRFUEL
with Non-RFS-FRFUEL or RFS-FRFUEL 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-
FRFUEL remains segregated throughout the distribution system.
(3) The petition described in this section must be submitted to EPA
along with the application for a small refinery or small refiner
exemption under this subpart.
(m) Additional attest requirements for importers of RFS-FRFUEL. The
following additional procedures shall be carried out by any importer of
RFS-FRFUEL as part of the attest engagement required for importers
under this subpart M.
(1) Obtain listings of all tenders of RFS-FRFUEL. Agree the total
volume of tenders from the listings to the transportation fuel
inventory reconciliation analysis required in Sec. 80.133(b), and to
the volumes determined by the third party under paragraph (d) of this
section.
(2) For each tender under paragraph (m)(1) of this section, where
the transportation fuel is loaded onto a marine vessel, report as a
finding the name and country of registration of each vessel, and the
volumes of RFS-FRFUEL loaded onto each vessel.
(3) Select a sample from the list of vessels identified per
paragraph (m)(2) of this section used to transport RFS-FRFUEL, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform all the following:
(i) Obtain the report of the independent third party, under
paragraph (d) of this section.
(A) Agree the information in these reports with regard to vessel
identification and transportation fuel volume.
(B) Identify, and report as a finding, each occasion the load port
and port of entry volume results differ by more than the amount allowed
in paragraph (e)(2) of this section, and determine whether all of the
requirements of paragraph (e)(2) of this section have been met.
(ii) Obtain the documents used by the independent third party to
determine transportation and storage of the RFS-FRFUEL from the
refinery to the load port, under paragraph (d) of this section. Obtain
tank activity records for any storage tank where the RFS-FRFUEL is
stored, and pipeline activity records for any pipeline used to
transport the RFS-FRFUEL prior to being loaded onto the vessel. Use
these records to determine whether the RFS-FRFUEL was produced at the
refinery that is the subject of the attest engagement, and whether the
RFS-FRFUEL was mixed with any Non-RFS-FRFUEL or any RFS-FRFUEL produced
at a different refinery.
(4) Select a sample from the list of vessels identified per
paragraph (m)(2) of this section used to transport RFS-FRFUEL, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform all 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.
[[Page 25138]]
(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-FRFUEL, and
perform all the following:
(i) Agree the volume of tenders from the listings to the
transportation fuel inventory reconciliation analysis in Sec.
80.133(b).
(ii) Obtain a separate listing of the tenders under this paragraph
(m)(5) where the transportation fuel 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 transportation
fuel was off loaded for the selected vessels. Determine and report as a
finding the country where the transportation fuel was off loaded for
each vessel selected.
(6) In order to complete the requirements of this paragraph (m), an
auditor shall do all the following:
(i) Be independent of the foreign refiner or importer.
(ii) Be licensed as a Certified Public Accountant in the United
States and a citizen of the United States, or be approved in advance by
EPA based on a demonstration of ability to perform the procedures
required in Sec. Sec. 80.125 through 80.127, 80.130, 80.1464, and this
paragraph (m).
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities and documents
relevant to compliance with the requirements of Sec. Sec. 80.125
through 80.127, 80.130, 80.1464, and this paragraph (m).
(n) Withdrawal or suspension of foreign small refiner or foreign
small refinery status. EPA may withdraw or suspend a foreign refiner's
small refinery or small refiner exemption where:
(1) A foreign refiner fails to meet any requirement of this
section;
(2) A foreign government fails to allow EPA inspections as provided
in paragraph (f)(1) of this section;
(3) A foreign refiner asserts a claim of, or a right to claim,
sovereign immunity in an action to enforce the requirements in this
subpart; or
(4) A foreign refiner fails to pay a civil or criminal penalty that
is not satisfied using the foreign refiner bond specified in paragraph
(h) of this section.
(o) Additional requirements for applications, reports and
certificates. Any application for a small refinery or small refiner
exemption, alternative procedures under paragraph (l) of this section,
any report, certification, or other submission required under this
section shall be:
(1) Submitted in accordance with procedures specified by the
Administrator, including use of any forms that may be specified by the
Administrator.
(2) Signed by the president or owner of the foreign refiner
company, or by that party's immediate designee, and shall contain the
following declaration:
``I hereby certify: (1) That I have actual authority to sign on
behalf of and to bind [insert name of foreign 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 M, 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 M, including 40
CFR 80.1465 apply to [INSERT NAME OF FOREIGN REFINER]. Pursuant to
Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for
furnishing false, incomplete or misleading information in this
certification or submission is a fine of up to $10,000 U.S., and/or
imprisonment for up to five years.''.
Sec. 80.1466 What are the additional requirements under this subpart
for foreign producers and importers of renewable fuels?
(a) Foreign producer of renewable fuel. For purposes of this
subpart, a foreign producer of renewable fuel is a party located
outside the United States, the Commonwealth of Puerto Rico, the Virgin
Islands, Guam, American Samoa, and the Commonwealth of the Northern
Mariana Islands (collectively referred to in this section as ``the
United States'') that has been approved by EPA to assign RINs to
renewable fuel that the foreign producer produces and exports to the
United States, hereinafter referred to as a ``foreign producer'' under
this section.
(b) General requirements. An approved foreign producer under this
section must meet all requirements that apply to renewable fuel
producers under this subpart.
(c) Designation, foreign producer certification, and product
transfer documents. (1) Any approved foreign producer under this
section must designate each batch of renewable fuel as ``RFS-FRRF'' at
the time the renewable fuel is produced.
(2) On each occasion when RFS-FRRF is loaded onto a vessel or other
transportation mode for transport to the United States, the foreign
producer shall prepare a certification for each batch of RFS-FRRF; the
certification shall include the report of the independent third party
under paragraph (d) of this section, and all the following additional
information:
(i) The name and EPA registration number of the company that
produced the RFS-FRRF.
(ii) The identification of the renewable fuel as RFS-FRRF.
(iii) The volume of RFS-FRRF being transported, in gallons.
(3) On each occasion when any party transfers custody or title to
any RFS-FRRF prior to its being imported into the United States, it
must include all the following information as part of the product
transfer document information:
(i) Designation of the renewable fuel as RFS-FRRF.
(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-FRRF is loaded onto a vessel for transport to
the United States the foreign producer shall have an independent third
party do all the following:
(i) Inspect the vessel prior to loading and determine the volume of
any tank bottoms.
(ii) Determine the volume of RFS-FRRF loaded onto the vessel
(exclusive of any tank bottoms before loading).
(iii) Obtain the EPA-assigned registration number of the foreign
producer.
(iv) Determine the name and country of registration of the vessel
used to transport the RFS-FRRF to the United States.
(v) Determine the date and time the vessel departs the port serving
the foreign producer.
(vi) Review original documents that reflect movement and storage of
the RFS-FRRF from the foreign producer to the load port, and from this
review determine all the following:
(A) The facility at which the RFS-FRRF was produced.
(B) That the RFS-FRRF remained segregated from Non-RFS-FRRF and
other RFS-FRRF produced by a different foreign producer.
(2) The independent third party shall submit a report to the
following:
[[Page 25139]]
(i) The foreign producer, containing the information required under
paragraph (d)(1) of this section, to accompany the product transfer
documents for the vessel.
(ii) The Administrator, containing the information required under
paragraph (d)(1) of this section, within thirty days following the date
of the independent third party's inspection. This report shall include
a description of the method used to determine the identity of the
foreign producer facility at which the renewable fuel was produced,
assurance that the renewable fuel remained segregated as specified in
paragraph (j)(1) of this section, and a description of the renewable
fuel's movement and storage between production at the source facility
and vessel loading.
(3) The independent third party must:
(i) Be approved in advance by EPA, based on a demonstration of
ability to perform the procedures required in this paragraph (d);
(ii) Be independent under the criteria specified in Sec.
80.65(e)(2)(iii); and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities, facilities and
documents relevant to compliance with the requirements of this
paragraph (d).
(e) Comparison of load port and port of entry testing. (1)(i) Any
foreign producer and any United States importer of RFS-FRRF shall
compare the results from the load port testing under paragraph (d) of
this section, with the port of entry testing as reported under
paragraph (k) of this section, for the volume of renewable fuel, except
as specified in paragraph (e)(1)(ii) of this section.
(ii) Where a vessel transporting RFS-FRRF off loads the renewable
fuel 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 renewable fuel
between the first United States port of entry and the subsequent port
of entry.
(2)(i) If the temperature-corrected volumes determined at the port
of entry and at the load port differ by more than one percent, the
number of RINs associated with the renewable fuel shall be calculated
based on the lesser of the two volumes in paragraph (e)(1)(i) of this
section.
(ii) Where the port of entry volume is the lesser of the two
volumes in paragraph (e)(1)(i) of this section, the importer shall
calculate the difference between the number of RINs originally assigned
by the foreign producer and the number of RINs calculated under Sec.
80.1426 for the volume of renewable fuel as measured at the port of
entry, and retire that amount of RINs in accordance with paragraph
(k)(4) of this section.
(f) Foreign producer commitments. Any foreign producer shall commit
to and comply with the provisions contained in this paragraph (f) as a
condition to being approved as a foreign producer under this subpart.
(1) Any United States Environmental Protection Agency inspector or
auditor must be given full, complete, and immediate access to conduct
inspections and audits of the foreign producer facility.
(i) Inspections and audits may be either announced in advance by
EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Renewable fuel is produced;
(B) Documents related to renewable fuel producer operations are
kept; and
(C) RFS-FRRF is stored or transported between the foreign producer
and the United States, including storage tanks, vessels and pipelines.
(iii) Inspections and audits may be by EPA employees or contractors
to EPA.
(iv) Any documents requested that are related to matters covered by
inspections and audits must be provided to an EPA inspector or auditor
on request.
(v) Inspections and audits by EPA may include review and copying of
any documents related to the following:
(A) The volume of RFS-FRRF.
(B) The proper classification of gasoline as being RFS-FRRF.
(C) Transfers of title or custody to RFS-FRRF.
(D) Work performed and reports prepared by independent third
parties and by independent auditors under the requirements of this
section, including work papers.
(vi) Inspections and audits by EPA may include interviewing
employees.
(vii) Any employee of the foreign producer must be made available
for interview by the EPA inspector or auditor, on request, within a
reasonable time period.
(viii) English language translations of any documents must be
provided to an EPA inspector or auditor, on request, within 10 working
days.
(ix) English language interpreters must be provided to accompany
EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of
Columbia shall be named, and service on this agent constitutes service
on the foreign producer or any employee of the foreign producer for any
action by EPA or otherwise by the United States related to the
requirements of this subpart.
(3) The forum for any civil or criminal enforcement action related
to the provisions of this section for violations of the Clean Air Act
or regulations promulgated thereunder shall be governed by the Clean
Air Act, including the EPA administrative forum where allowed under the
Clean Air Act.
(4) United States substantive and procedural laws shall apply to
any civil or criminal enforcement action against the foreign producer
or any employee of the foreign producer related to the provisions of
this section.
(5) Applying to be an approved foreign producer under this section,
or producing or exporting renewable fuel under such approval, and all
other actions to comply with the requirements of this subpart relating
to such approval constitute actions or activities covered by and within
the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with
respect to actions instituted against the foreign producer, its agents
and employees in any court or other tribunal in the United States for
conduct that violates the requirements applicable to the foreign
producer under this subpart, including conduct that violates the False
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6) The foreign producer, or its agents or employees, will not seek
to detain or to impose civil or criminal remedies against EPA
inspectors or auditors, whether EPA employees or EPA contractors, for
actions performed within the scope of EPA employment related to the
provisions of this section.
(7) The commitment required by this paragraph (f) shall be signed
by the owner or president of the foreign producer company.
(8) In any case where RFS-FRRF produced at a foreign producer
facility is stored or transported by another company between the
refinery and the vessel that transports the RFS-FRRF to the United
States, the foreign producer shall obtain from each such other company
a commitment that meets the requirements specified in paragraphs (f)(1)
through (7) of this section, and these commitments shall be included in
the foreign producer's application to be an approved foreign producer
under this subpart.
(g) Sovereign immunity. By submitting an application to be an
approved foreign producer under this
[[Page 25140]]
subpart, or by producing and exporting renewable fuel to the United
States under such approval, the foreign producer, and its agents and
employees, without exception, become subject to the full operation of
the administrative and judicial enforcement powers and provisions of
the United States without limitation based on sovereign immunity, with
respect to actions instituted against the foreign producer, its agents
and employees in any court or other tribunal in the United States for
conduct that violates the requirements applicable to the foreign
producer under this subpart, including conduct that violates the False
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(h) Bond posting. Any foreign producer shall meet the requirements
of this paragraph (h) as a condition to approval as a foreign producer
under this subpart.
(1) The foreign producer shall post a bond of the amount calculated
using the following equation:
Bond = G * $ 0.01
Where:
Bond = amount of the bond in U.S. dollars.
G = the largest volume of renewable fuel produced at the foreign
producer's facility and exported to the United States, in gallons,
during a single calendar year among the most recent of the following
calendar years, up to a maximum of five calendar years: the calendar
year immediately preceding the date the refinery's application is
submitted, the calendar year the application is submitted, and each
succeeding calendar year.
(2) Bonds shall be posted by any of the following methods:
(i) Paying the amount of the bond to the Treasurer of the United
States.
(ii) Obtaining a bond in the proper amount from a third party
surety agent that is payable to satisfy United States administrative or
judicial judgments against the foreign producer, provided EPA agrees in
advance as to the third party and the nature of the surety agreement.
(iii) An alternative commitment that results in assets of an
appropriate liquidity and value being readily available to the United
States provided EPA agrees in advance as to the alternative commitment.
(3) Bonds posted under this paragraph (h) shall:
(i) Be used to satisfy any judicial judgment that results from an
administrative or judicial enforcement action for conduct in violation
of this subpart, including where such conduct violates the False
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii) Be provided by a corporate surety that is listed in the United
States 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 producer produces renewable fuel pursuant to the
requirements of this subpart.
(4) On any occasion a foreign producer bond is used to satisfy any
judgment, the foreign producer shall increase the bond to cover the
amount used within 90 days of the date the bond is used.
(5) If the bond amount for a foreign producer increases, the
foreign producer shall increase the bond to cover the shortfall within
90 days of the date the bond amount changes. If the bond amount
decreases, the foreign refiner may reduce the amount of the bond
beginning 90 days after the date the bond amount changes.
(i) English language reports. Any document submitted to EPA by a
foreign producer shall be in English, or shall include an English
language translation.
(j) Prohibitions. (1) No party may combine RFS-FRRF with any Non-
RFS-FRRF, and no party may combine RFS-FRRF with any RFS-FRRF produced
at a different refinery, until the importer has met all the
requirements of paragraph (k) of this section.
(2) No foreign producer or other party may cause another party to
commit an action prohibited in paragraph (j)(1) of this section, or
that otherwise violates the requirements of this section.
(k) Requirements for United States importers of RFS-FRRF. Any
United States importer shall meet all the following requirements:
(1) Each batch of imported RFS-FRRF shall be classified by the
importer as being RFS-FRRF.
(2) Renewable fuel shall be classified as RFS-FRRF according to the
designation by the foreign producer if this designation is supported by
product transfer documents prepared by the foreign producer as required
in paragraph (c) of this section.
(3) For each renewable fuel batch classified as RFS-FRRF, any
United States importer shall have an independent third party do all the
following:
(i) Determine the volume of gasoline in the vessel.
(ii) Use the foreign producer's RFS-FRRF certification to determine
the name and EPA-assigned registration number of the foreign producer
that produced the RFS-FRRF.
(iii) Determine the name and country of registration of the vessel
used to transport the RFS-FRRF to the United States.
(iv) Determine the date and time the vessel arrives at the United
States port of entry.
(4) Where the importer is required to retire RINs under paragraph
(e)(2) of this section, the importer must report the retired RINs in
the applicable reports under Sec. 80.1452.
(5) Any importer shall submit reports within 30 days following the
date any vessel transporting RFS-FRRF arrives at the United States port
of entry to all the following:
(i) The Administrator, containing the information determined under
paragraph (k)(3) of this section.
(ii) The foreign producer, containing the information determined
under paragraph (k)(3)(i) of this section, and including identification
of the port at which the product was off loaded, and any RINs retired
under paragraph (e)(2) of this section.
(6) Any United States importer shall meet all other requirements of
this subpart for any imported ethanol or other renewable fuel that is
not classified as RFS-FRRF under paragraph (k)(2) of this section.
(l) Truck imports of RFS-FRRF produced by a foreign producer. (1)
Any foreign producer whose RFS-FRRF is transported into the United
States by truck may petition EPA to use alternative procedures to meet
all the following requirements:
(i) Certification under paragraph (c)(2) of this section.
(ii) Load port and port of entry testing under paragraphs (d) and
(e) of this section.
(iii) Importer testing under paragraph (k)(3) of this section.
(2) These alternative procedures must ensure RFS-FRRF remains
segregated from Non-RFS-FRRF until it is imported into the United
States. The petition will be evaluated based on whether it adequately
addresses the following:
(i) Contracts with any facilities that receive and/or transport
RFS-FRRF that prohibit the commingling of RFS-FRRF with Non-RFS-FRRF or
RFS-FRRF from other foreign producers.
(ii) Attest procedures to be conducted annually by an independent
third party that review loading records and import documents based on
volume
[[Page 25141]]
reconciliation to confirm that all RFS-FRRF remains segregated.
(3) The petition described in this section must be submitted to EPA
along with the application for approval as a foreign producer under
this subpart.
(m) Additional attest requirements for producers of RFS-FRRF. The
following additional procedures shall be carried out by any producer of
RFS-FRRF as part of the attest engagement required for renewable fuel
producers under this subpart M.
(1) Obtain listings of all tenders of RFS-FRRF. Agree the total
volume of tenders from the listings to the volumes determined by the
third party under paragraph (d) of this section.
(2) For each tender under paragraph (m)(1) of this section, where
the renewable fuel is loaded onto a marine vessel, report as a finding
the name and country of registration of each vessel, and the volumes of
RFS-FRRF 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-FRRF, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform all 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 renewable fuel volume.
(B) Identify, and report as a finding, each occasion the load port
and port of entry volume results differ by more than the amount allowed
in paragraph (e) of this section, and determine whether the importer
retired the appropriate amount of RINs as required under paragraph
(e)(2) of this section, and submitted the applicable reports under
Sec. 80.1452 in accordance with paragraph (k)(4) of this section.
(ii) Obtain the documents used by the independent third party to
determine transportation and storage of the RFS-FRRF from the foreign
producer's facility to the load port, under paragraph (d) of this
section. Obtain tank activity records for any storage tank where the
RFS-FRRF is stored, and activity records for any mode of transportation
used to transport the RFS-FRFUEL prior to being loaded onto the vessel.
Use these records to determine whether the RFS-FRRF was produced at the
foreign producer's facility that is the subject of the attest
engagement, and whether the RFS-FRRF was mixed with any Non-RFS-FRRF or
any RFS-FRRF produced at a different facility.
(4) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRRF, 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 a separate listing of the tenders under this paragraph
(m)(5) where the RFS-FRRF 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 renewable fuel was
off loaded for the selected vessels. Determine and report as a finding
the country where the renewable fuel was off loaded for each vessel
selected.
(6) In order to complete the requirements of this paragraph (m) an
auditor shall:
(i) Be independent of the foreign producer;
(ii) Be licensed as a Certified Public Accountant in the United
States and a citizen of the United States, or be approved in advance by
EPA based on a demonstration of ability to perform the procedures
required in Sec. Sec. 80.125 through 80.127, 80.130, 80.1464, and this
paragraph (m); and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities and documents
relevant to compliance with the requirements of Sec. Sec. 80.125
through 80.127, 80.130, 80.1464, and this paragraph (m).
(n) Withdrawal or suspension of foreign producer approval. EPA may
withdraw or suspend a foreign producer's approval where any of the
following occur:
(1) A foreign producer fails to meet any requirement of this
section.
(2) A foreign government fails to allow EPA inspections as provided
in paragraph (f)(1) of this section.
(3) A foreign producer asserts a claim of, or a right to claim,
sovereign immunity in an action to enforce the requirements in this
subpart.
(4) A foreign producer fails to pay a civil or criminal penalty
that is not satisfied using the foreign producer bond specified in
paragraph (g) of this section.
(o) Additional requirements for applications, reports and
certificates. Any application for approval as a foreign producer,
alternative procedures under paragraph (l) of this section, any report,
certification, or other submission required under this section shall
be:
(1) Submitted in accordance with procedures specified by the
Administrator, including use of any forms that may be specified by the
Administrator.
(2) Signed by the president or owner of the foreign producer
company, or by that party's immediate designee, and shall contain the
following declaration:
``I hereby certify: 1) That I have actual authority to sign on behalf
of and to bind [insert name of foreign producer] with regard to all
statements contained herein; 2) that I am aware that the information
contained herein is being Certified, or submitted to the United States
Environmental Protection Agency, under the requirements of 40 CFR part
80, subpart M, 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 M, including 40 CFR 80.1465
apply to [insert name of foreign producer]. Pursuant to Clean Air Act
section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false,
incomplete or misleading information in this certification or
submission is a fine of up to $10,000 U.S., and/or imprisonment for up
to five years.''.
Sec. 80.1467 What are the additional requirements under this subpart
for a foreign RIN owner?
(a) Foreign RIN owner. For purposes of this subpart, a foreign RIN
owner is a party located outside the United States, the Commonwealth of
Puerto Rico, the Virgin Islands, Guam, American Samoa, and the
Commonwealth of the Northern Mariana Islands (collectively referred to
in this section as ``the United States'') that has been approved by EPA
to own RINs.
(b) General requirement. An approved foreign RIN owner must meet
all requirements that apply to parties who own RINs under this subpart.
[[Page 25142]]
(c) Foreign RIN owner commitments. Any party shall commit to and
comply with the provisions contained in this paragraph (c) as a
condition to being approved as a foreign RIN owner under this subpart.
(1) Any United States Environmental Protection Agency inspector or
auditor must be given full, complete, and immediate access to conduct
inspections and audits of the foreign RIN owner's place of business.
(i) Inspections and audits may be either announced in advance by
EPA, or unannounced.
(ii) Access will be provided to any location where documents
related to RINs the foreign RIN owner has obtained, sold, transferred
or held are kept.
(iii) Inspections and audits may be by EPA employees or contractors
to EPA.
(iv) Any documents requested that are related to matters covered by
inspections and audits must be provided to an EPA inspector or auditor
on request.
(v) Inspections and audits by EPA may include review and copying of
any documents related to the following:
(A) Transfers of title to RINs.
(B) Work performed and reports prepared by independent auditors
under the requirements of this section, including work papers.
(vi) Inspections and audits by EPA may include interviewing
employees.
(vii) Any employee of the foreign RIN owner must be made available
for interview by the EPA inspector or auditor, on request, within a
reasonable time period.
(viii) English language translations of any documents must be
provided to an EPA inspector or auditor, on request, within 10 working
days.
(ix) English language interpreters must be provided to accompany
EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of
Columbia shall be named, and service on this agent constitutes service
on the foreign RIN owner or any employee of the foreign RIN owner for
any action by EPA or otherwise by the United States related to the
requirements of this subpart.
(3) The forum for any civil or criminal enforcement action related
to the provisions of this section for violations of the Clean Air Act
or regulations promulgated thereunder shall be governed by the Clean
Air Act, including the EPA administrative forum where allowed under the
Clean Air Act.
(4) United States substantive and procedural laws shall apply to
any civil or criminal enforcement action against the foreign RIN owner
or any employee of the foreign RIN owner related to the provisions of
this section.
(5) Submitting an application to be a foreign RIN owner, and all
other actions to comply with the requirements of this subpart
constitute actions or activities covered by and within the meaning of
the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to
actions instituted against the foreign RIN owner, its agents and
employees in any court or other tribunal in the United States for
conduct that violates the requirements applicable to the foreign RIN
owner under this subpart, including conduct that violates the False
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6) The foreign RIN owner, or its agents or employees, will not
seek to detain or to impose civil or criminal remedies against EPA
inspectors or auditors, whether EPA employees or EPA contractors, for
actions performed within the scope of EPA employment related to the
provisions of this section.
(7) The commitment required by this paragraph (c) shall be signed
by the owner or president of the foreign RIN owner business.
(d) Sovereign immunity. By submitting an application to be a
foreign RIN owner under this subpart, the foreign entity, and its
agents and employees, without exception, become subject to the full
operation of the administrative and judicial enforcement powers and
provisions of the United States without limitation based on sovereign
immunity, with respect to actions instituted against the foreign RIN
owner, its agents and employees in any court or other tribunal in the
United States for conduct that violates the requirements applicable to
the foreign RIN owner under this subpart, including conduct that
violates the False Statements Accountability Act of 1996 (18 U.S.C.
1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(e) Bond posting. Any foreign entity shall meet the requirements of
this paragraph (e) as a condition to approval as a foreign RIN owner
under this subpart.
(1) The foreign entity shall post a bond of the amount calculated
using the following equation:
Bond = G * $ 0.01
Where:
Bond = amount of the bond in U.S. dollars.
G = the total of the number of gallon-RINs the foreign entity
expects to sell or transfer during the first calendar year that the
foreign entity is a RIN owner, plus the number of gallon-RINs the
foreign entity expects to sell or transfer during the next four
calendar years. After the first calendar year, the bond amount shall
be based on the actual number of gallon-RINs sold or transferred
during the current calendar year and the number held at the
conclusion of the current averaging year, plus the number of gallon-
RINs sold or transferred during the four most recent calendar years
preceding the current calendar year. For any year for which there
were fewer than four preceding years in which the foreign entity
sold or transferred RINs, the bond shall be based on the total of
the number of gallon-RINs sold or transferred during the current
calendar year and the number held at the end of the current calendar
year, plus the number of gallon-RINs sold or transferred during any
calendar year preceding the current calendar year, plus the number
of gallon-RINs expected to be sold or transferred during subsequent
calendar years, the total number of years not to exceed four
calendar years in addition to the current calendar year.
(2) Bonds shall be posted by doing any of the following:
(i) Paying the amount of the bond to the Treasurer of the United
States.
(ii) Obtaining a bond in the proper amount from a third party
surety agent that is payable to satisfy United States administrative or
judicial judgments against the foreign RIN owner, provided EPA agrees
in advance as to the third party and the nature of the surety
agreement.
(iii) An alternative commitment that results in assets of an
appropriate liquidity and value being readily available to the United
States, provided EPA agrees in advance as to the alternative
commitment.
(3) All the following shall apply to bonds posted under this
paragraph (e); bonds 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''.
(iii) Include a commitment that the bond will remain in effect for
at least five years following the end of latest reporting period in
which the foreign RIN owner obtains, sells, transfers, or holds RINs.
(4) On any occasion a foreign RIN owner bond is used to satisfy any
judgment, the foreign RIN owner shall increase the bond to cover the
amount
[[Page 25143]]
used within 90 days of the date the bond is used.
(f) English language reports. Any document submitted to EPA by a
foreign RIN owner shall be in English, or shall include an English
language translation.
(g) Prohibitions. (1) A foreign RIN owner is prohibited from
obtaining, selling, transferring, or holding any RIN that is in excess
of the number for which the bond requirements of this section have been
satisfied.
(2) Any RIN that is sold, transferred, or held that is in excess of
the number for which the bond requirements of this section have been
satisfied is an invalid RIN under Sec. 80.1431.
(3) Any RIN that is obtained from a party located outside the
United States that is not an approved foreign RIN owner under this
section is an invalid RIN under Sec. 80.1431.
(4) No foreign RIN owner or other party may cause another party to
commit an action prohibited in this paragraph (g), or that otherwise
violates the requirements of this section.
(h) Additional attest requirements for foreign RIN owners. The
following additional requirements apply to any foreign RIN owner as
part of the attest engagement required for RIN owners under this
subpart M.
(i) The attest auditor must be independent of the foreign RIN
owner.
(ii) The attest auditor must be licensed as a Certified Public
Accountant in the United States and a citizen of the United States, or
be approved in advance by EPA based on a demonstration of ability to
perform the procedures required in Sec. Sec. 80.125 through 80.127,
80.130, and 80.1464.
(iii) The attest auditor must sign a commitment that contains the
provisions specified in paragraph (c) of this section with regard to
activities and documents relevant to compliance with the requirements
of Sec. Sec. 80.125 through 80.127, 80.130, and 80.1464.
(i) Withdrawal or suspension of foreign RIN owner status. EPA may
withdraw or suspend its approval of a foreign RIN owner where any of
the following occur:
(1) A foreign RIN owner fails to meet any requirement of this
section, including, but not limited to, the bond requirements.
(2) A foreign government fails to allow EPA inspections as provided
in paragraph (c)(1) of this section.
(3) A foreign RIN owner asserts a claim of, or a right to claim,
sovereign immunity in an action to enforce the requirements in this
subpart.
(4) A foreign RIN owner fails to pay a civil or criminal penalty
that is not satisfied using the foreign RIN owner bond specified in
paragraph (e) of this section.
(j) Additional requirements for applications, reports and
certificates. Any application for approval as a foreign RIN owner, any
report, certification, or other submission required under this section
shall be:
(1) Submitted in accordance with procedures specified by the
Administrator, including use of any forms that may be specified by the
Administrator.
(2) Signed by the president or owner of the foreign RIN owner
company, or by that party's immediate designee, and shall contain the
following declaration:
``I hereby certify: 1) That I have actual authority to sign on behalf
of and to bind [insert name of foreign RIN owner] with regard to all
statements contained herein; 2) that I am aware that the information
contained herein is being Certified, or submitted to the United States
Environmental Protection Agency, under the requirements of 40 CFR part
80, subpart M, 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 M, including 40 CFR 80.1467
apply to [insert name of foreign RIN owner]. Pursuant to Clean Air Act
section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false,
incomplete or misleading information in this certification or
submission is a fine of up to $10,000 U.S., and/or imprisonment for up
to five years.''.
Sec. 80.1468 [Reserved]
Sec. 80.1469 What are the labeling requirements that apply to
retailers and wholesale purchaser-consumers of ethanol fuel blends that
contain greater than 10 volume percent ethanol?
(a) Any retailer or wholesale purchaser-consumer who sells,
dispenses, or offers for sale or dispensing, ethanol fuel blends that
contain greater than 10 volume percent ethanol must prominently and
conspicuously display in the immediate area of each pump stand from
which such fuel is offered for sale or dispensing, the following
legible label in block letters of no less than 24-point bold type in a
color contrasting with the background:
CONTAINS MORE THAN 10 VOLUME PERCENT ETHANOL
For use only in flexible-fuel gasoline vehicles.
May damage non-flexible fuel vehicles.
WARNING
Federal law prohibits use in non-flexible fuel vehicles.
(b) Alternative labels to those specified in paragraph (a) of this
section may be used as approved by EPA. Requests for approval of
alternative labels shall be sent to one of the following addresses:
(1) For US mail: U.S. EPA, Attn: Alternative fuel dispenser label
request, 6406J, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
(2) For overnight or courier services: U.S. EPA, Attn: Alternative
fuel dispenser label request, 6406J, 1310 L Street, NW., 6th floor,
Washington, DC 20005. (202) 343-9038.
[FR Doc. E9-10978 Filed 5-22-09; 8:45 am]
BILLING CODE 6560-50-P