Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program

Federal RegisterMay 26, 2009

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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.

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 (NO

) 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

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:

Category

NAICS

codes

SIC

codes

Examples of potentially regulated entities

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.

North American Industry Classification System (NAICS).

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

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

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 PM

2.5

, Ozone and Air Toxics

2. Impacts of Proposed Standards on Future Ambient Concentrations of PM

2.5

, 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

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),

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

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.

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).

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.

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 (NO

), 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

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

biofuel

requirement

Biomass-

based diesel

requirement

Advanced

biofuel

requirement

Total

renewable fuel

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

2.75

16.55

2014

1.75

3.75

18.15

2015

3.0

5.5

20.5

2016

4.25

7.25

22.25

2017

5.5

9.0

24.0

2018

7.0

11.0

26.0

2019

8.5

13.0

28.0

2020

10.5

15.0

30.0

2021

13.5

18.0

33.0

2022

16.0

21.0

36.0

2023+

To be determined by EPA through a future rulemaking, but no less than 1.0 billion gallons.

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

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.

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

Advanced biofuel

Biomass-based diesel

Cellulosic biofuel

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.

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 § 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

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.

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

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

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 CO

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 CO

-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 CO

-eq. over the 30 year period or an average annualized emission rate reduction of 150 million metric tons of CO

-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

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.

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.

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

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 NO

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, NO

, 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

Pollutant

RFS1 base

Annual short tons

% of total U.S. inventory

RFS1 mandate

Annual short tons

% of total U.S. inventory

AEO2007

Annual short tons

% of total U.S. inventory

312,400

2.8

274,982

2.5

195,735

1.7

112,401

1.0

72,362

0.6

−8,193

−0.07

50,305

1.4

37,147

1.0

9,276

0.3

2.5

14,321

0.4

11,452

0.3

5,376

0.16

−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

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

0.03

0.02

−1

−0.01

Acrolein

290

5.0

252

4.4

174

3.0

28,770

0.3

4,461

0.05

−47,030

−0.5

−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

Pollutant

RFS1 base

Annual short tons

% of total U.S. inventory

RFS1 mandate

Annual short tons

% of total U.S. inventory

AEO2007

Annual short tons

% of total U.S. inventory

402,795

3.6

341,028

3.0

210,217

1.9

100,313

0.9

63,530

0.6

−15,948

−0.14

46,193

1.3

33,035

0.9

5,164

0.15

2.5

10,535

0.3

7,666

0.2

1,589

0.05

−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

28,770

0.3

4,461

0.05

−47,030

−0.5

−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 PM

2.5

, 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 PM

2.5

, 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

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

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

Cellulosic biomass ethanol

Cellulosic biofuel.

Any renewable fuel that is not cellulosic biomass ethanol

Biomass-based diesel.

Not applicable

Advanced biofuel.

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.

Table III.A-2—Alternative D Code Definitions

D value

Meaning under RFS1

Meaning under RFS2

Cellulosic biomass ethanol

Not applicable.

Any renewable fuel that is not cellulosic biomass ethanol

Not applicable.

Not applicable

Cellulosic biofuel.

Not applicable

Biomass-based diesel.

Not applicable

Advanced biofuel.

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

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.

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).

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

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.

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.

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.

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

Advanced biofuel

Biomass-based diesel

Cellulosic biofuel

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.

Facilities that commenced construction before December 19, 2007 are “grandfathered” and thereby exempt from the 20% GHG reduction requirement.

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.

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.

For ease of reference, we will refer to both these provisions as the “exemption provisions” of EISA.

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

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

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 Unite

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