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[Federal Register: May 26, 2009 (Volume 74, Number 99)]
[Proposed Rules]
[Page 24903-25143]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr26my09-21]
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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
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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: asdinfo@epa.gov.
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: macallister.julia@epa.gov, or Assessment and Standards
Division Hotline; telephone number (734) 214-4636; E-mail address
asdinfo@epa.gov.
SUPPLEMENTARY INFORMATION:
General Information
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
[[Page 24907]]
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
[[Page 24908]]
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
[[Continued on page 24953]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 24953-25002]] Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel
Standard Program
[[Continued from page 24952]]
[[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.
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\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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
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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 bu