Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program

Federal RegisterSep 22, 2006

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-OAR-2005-0161; FRL-8218-8]

RIN 2060-AN76

Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Notice of proposed rulemaking.

SUMMARY:

Under the Clean Air Act, as amended by Section 1501 of the Energy Policy Act of 2005, the Environmental Protection Agency is required to promulgate regulations implementing a renewable fuel program. The statute specifies the total volume of renewable fuel that needs to be used in each year, with the total volume increasing over time. In this context, it is expected to simultaneously reduce dependence on foreign sources of petroleum, increase domestic sources of energy, and help us make progress in moving beyond a petroleum-based economy. The increased use of renewable fuels such as ethanol and biodiesel is also expected to have the added benefit of providing an expanded market for agricultural products such as corn and soybeans, expanding economic benefits for our nation's agricultural sector. Based on our analysis, there is also reason to believe that the expanded use of renewable fuels will provide reductions in carbon dioxide emissions and some air toxics emissions, such as benzene, from the transportation sector, while other emissions may increase.

This action proposes regulations designed to ensure that refiners, blenders, and importers of gasoline will use enough renewable fuel each year so that this total volume requirement is met. Our proposal describes the standard that will apply to these parties and the renewable fuels that qualify for compliance. The regulations would also establish a trading program that would be a critical aspect of the overall program, allowing renewable fuels to be used where they are most economical while providing a flexible means for obligated parties to comply with the standard.

DATES:

Comments:

Comments must be received on or before November 12, 2006. Under the Paperwork Reduction Act, comments on the information collection provisions must be received by OMB on or before October 30, 2006.

Hearing:

A public hearing will be held at 10 a.m. (Central) on October 13, 2006 at the Sheraton Gateway Suites Chicago O'Hare in Rosemont, IL. To request to speak at a public hearing, send a request to the contact in

FOR FURTHER INFORMATION CONTACT

by October 4, 2006.

ADDRESSES:

Comments:

Submit your comments, identified by Docket ID No. EPA-OAR-2005-0161, by one of the following methods:

•

http://www.regulations.gov:

Follow the on-line instructions for submitting comments.

• E-mail:

ASDinfo@epa.gov.

• Mail: U.S. Environmental Protection Agency, EPA West (Air Docket), 1200 Pennsylvania Ave., NW., Room B108, Mail Code 6102T, Washington, DC 20460, Attention Docket ID No. OAR-2005-0161. Please include a total of 2 copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC 20503.

• Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington DC. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.

Instructions:

Direct your comments to Docket ID No. EPA-OAR-2005-0161. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at

www.regulations.gov,

including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or e-mail. The

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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

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your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses.

Docket:

All documents in the docket are listed in the

www.regulations.gov

index. Although listed in the index, some information is not publicly available,

e.g.

, CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in

www.regulations.gov

or in hard copy at the EPA Docket Center, EPA/DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The Docket telephone number is (202) 566-1742. The telephone number for the Public Reading Room is (202) 566-1744.

Note:

The EPA Docket Center suffered damage due to flooding during the last week of June 2006. The Docket Center is continuing to operate. However, during the cleanup, there will be temporary changes to Docket Center telephone numbers, addresses, and hours of operation for people who wish to make hand deliveries or visit the Public Reading Room to view documents. Consult EPA's

Federal Register

notice at 71 FR 38147 (July 5, 2006) or the EPA Web site at

http://www.epa.gov/epahome/dockets.htm

for current information on docket operations, locations and telephone numbers. The Docket Center's mailing address for U.S. mail and the procedure for submitting comments to www.regulations.gov are not affected by the flooding and will remain the same.

Hearing:

The hearing will be held at 10 a.m. (Central) on October 13, 2006 at the Sheraton Gateway Suites Chicago O'Hare, 6501 North Mannheim Road, Rosemont, Illinois 60018. To request to speak at a public hearing, send a request to the contact in

FOR FURTHER INFORMATION CONTACT

FOR FURTHER INFORMATION CONTACT:

Julia MacAllister, U.S. EPA, National Vehicle and Fuel Emissions Laboratory, 2000 Traverwood, Ann Arbor, MI 48105; Telephone (734) 214-4131, FAX (734) 214-4816, E-mail

macallister.julia@epa.gov.

SUPPLEMENTARY INFORMATION:

I. General Information

A. Does This Action Apply to Me?

Entities potentially affected by this proposed action include those involved

with the production, distribution and sale of gasoline motor fuel or renewable fuels such as ethanol and biodiesel. Regulated categories and entities could include:

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 provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be affected by this proposed action. Other types of entities not listed in the table could also be affected. To decide whether your organization might be affected if this proposed action is finalized, you should carefully examine today's notice and the existing regulations in 40 CFR part 80. If you have any questions regarding the applicability of this action to a particular entity, consult the persons listed in the preceding

FOR FURTHER INFORMATION CONTACT

section.

B. What Should I Consider as I Prepare my Comments for EPA?

Submitting CBI.

Do not submit this information to EPA through

www.regulations.gov

or e-mail. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.

Tips for Preparing Your Comments.

When submitting comments, remember to:

• Identify the rulemaking by docket number and other identifying information (subject heading,

Federal Register

date and page number).

• Follow directions—The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.

• Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.

• Describe any assumptions and provide any technical information and/or data that you used.

• If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.

• Provide specific examples to illustrate your concerns, and suggest alternatives.

• Explain your views as clearly as possible, avoiding the use of profanity or personal threats.

• Make sure to submit your comments by the comment period deadline identified.

Docket Copying Costs.

A reasonable fee may be charged by EPA for copying docket materials, as provided in 40 CFR part 2.

Table of Contents

I. Background

A. The Role of Renewable Fuels in the Transportation Sector

B. Requirements in the Energy Policy Act

C. Default Standard Applicable to 2006

D. Development of the Proposal

II. Overview of the Proposal

A. Impacts of Increased Reliance on Renewable Fuels

1. Renewable Fuel Volumes Scenarios Analyzed

2. Emissions

3. Economic Impacts

4. Greenhouse Gases and Fossil Fuel Consumption

5. Potential Water Quality Impacts

B. Program Structure

1. What is the RFS Program Standard?

2. Who Must Meet the Standard?

3. What Qualifies as a Renewable Fuel?

4. Equivalence Values of Different Renewable Fuels

5. How Will Compliance Be Determined?

6. How Would the Trading Program Work?

7. How Would the Program Be Enforced?

C. Voluntary Labeling Program

III. Complying With the Renewable Fuel Standard

A. What Is the Standard That Must Be Met?

1. How Is the Percentage Standard Calculated?

2. What are the Applicable Standards?

3. Compliance in 2007

4. Renewable Volume Obligations

B. What Counts as a Renewable Fuel in the RFS Program?

1. What Is a Renewable Fuel That Can Be Used for Compliance?

a. Ethanol Made From a Cellulosic Feedstock

b. Ethanol Made From Any Feedstock in Facilities Run Mostly With Biomass-Based Fuel

c. Ethanol That Is Made From the Non-Cellulosic Portions of Animal, Other Waste, and Municipal Waste

2. What Is Biodiesel?

a. Biodiesel (Mono-Alkyl Esters)

b. Non-Ester Renewable Diesel

3. Is Motor Fuel That is Made From a Renewable Feedstock a Renewable Fuel?

4. What Are “Equivalence Values” for Renewable Fuel?

a. Authority Under the Act To Establish Equivalence Values

b. Energy Content and Renewable Content as the Basis for Equivalence Values

c. Lifecycle Analyses as the Basis for Equivalence Values

C. What Gasoline Is Used To Calculate the Renewable Fuel Obligation and Who Is Required To Meet the Obligation?

1. What Gasoline Is Used To Calculate the Volume of Renewable Fuel Required To Meet a Party's Obligation?

2. Who Is Required to Meet the Renewable Fuels Obligation?

3. What Exemptions Are Available Under the RFS Program?

a. Small Refinery and Small Refiner Exemption

b. General Hardship Exemption

c. Temporary Exemption Based on Unforeseen Circumstances

4. What Are the Opt-in and State Waiver Provisions Under the RFS Program?

a. Opt-in Provisions for Noncontiguous States and Territories

b. State Waiver Provisions

D. How Do Obligated Parties Comply With the Standard?

1. Why Use Renewable Identification Numbers?

a. RINs Serve the Purpose of a Credit Trading Program

b. Alternative Approach to Tracking Batches

2. Generating RINs and Assigning Them to Batches

a. Form of Renewable Identification Numbers

b. Generating Extra-Value RINs

c. Cases in Which RINs Are Not Generated

3. Calculating and Reporting Compliance

a. Using RINs To Meet the Standard

b. Valid Life of RINs

c. Cap on RIN Use To Address Rollover

d. Deficit Carryovers

4. Provisions for Exporters of Renewable Fuel

5. How Would the Agency Verify Compliance?

E. How Are RINs Distributed and Traded?

1. Distribution of RINs With Batches of Renewable Fuel

a. Responsibilities of Renewable Fuel Producers and Importers

b. Responsibilities of Parties That Buy, Sell, or Handle Renewable Fuels

i. Batch Splits

ii. Batch Mergers

2. Separation of RINs From Batches

3. Distribution of Separated RINs

4. Alternative Approaches to RIN Distribution

a. Producer With Direct Transfer of RINs

b. Producer With Open RIN Market

c. First Purchaser

d. Owner at Time of Blending

e. Blender at Time of Blending

IV. Registration, Recordkeeping, and Reporting Requirements

A. Introduction

B. Requirements for Obligated Parties and Exporters of Renewable Fuels

1. Registration

2. Reporting

3. Recordkeeping

C. Requirements for Producers and Importers of Renewable Fuel

1. Registration

2. Reporting

3. Recordkeeping

D. Requirements for Other Parties Who Own RINs

1. Registration

2. Reporting

3. Recordkeeping

V. What Acts Are Prohibited and Who I s Liable for Violations?

VI. Current and Projected Renewable Fuel Production and Use

A. Overview of U.S. Ethanol Industry and Future Production/Consumption

1. Current Ethanol Production

2. Expected Growth in Ethanol Production

3. Current Ethanol and MTBE Consumption

4. Expected Growth in Ethanol Consumption

B. Overview of Biodiesel Industry and Future Production/Consumption

1. Characterization of U.S. Biodiesel Production/Consumption

2. Expected Growth in U.S. Biodiesel Production/Consumption

C. Feasibility of the RFS Program Volume Obligations

1. Production Capacity of Ethanol and Biodiesel

2. Production Capacity of Cellulosic Ethanol

3. Renewable Fuel Distribution System Capability

VII. Impacts on Cost of Renewable Fuels and Gasoline

A. Renewable Fuel Production and Blending Costs

1. Ethanol Production Costs

a. Corn Ethanol

b. Cellulosic Ethanol

c. Ethanol's Blending Cost

2. Biodiesel Production Costs

3. Diesel Fuel Costs

B. Distribution Costs

1. Ethanol Distribution Costs

a. Capital Costs To Upgrade Distribution System for Increased Ethanol Volume

b. Ethanol Freight Costs

2. Biodiesel Distribution Costs

C. Estimated Costs to Gasoline

1. RVP Cost for Blending Ethanol Into Summertime RFG

2. Cost Savings for Phasing Out Methyl Tertiary Butyl Ether (MTBE)

3. Production of Alkylate From MTBE Feedstocks

4. Changes in Refinery Produced Gasoline Volume and Its Costs

5. Overall Impact on Fuel Cost

a. Cost Without Ethanol Subsidies

b. Gasoline Costs Including Ethanol Consumption Tax Subsidies

c. Cost Sensitivity Case Assuming $70 per Barrel Crude Oil

VIII. What Are the Impacts of Increased Ethanol Use on Emissions and Air Quality?

A. Effect of Renewable Fuel Use on Emissions

1. Emissions From Gasoline Fueled Motor Vehicles and Equipment

a. Gasoline Fuel Quality

b. Emissions From Motor Vehicles

c. Nonroad Equipment

2. Diesel Fuel Quality: Biodiesel

3. Renewable Fuel Production and Distribution

B. Impact on Emission Inventories

1. Primary Analysis

2. Sensitivity Analysis

3. Local and Regional VOC and NO

Emission Impacts in July

C. Impact on Air Quality

1. Impact of 7.2 Billion Gallon Ethanol Use on Ozone

2. Particulate Matter

IX. Impacts on Fossil Fuel Consumption and Related Implications

A. Lifecycle Modeling

1. Modifications to GREET Assumptions

a. Wet-Mill Versus Dry Mill Ethanol Plants

b. Coal Versus Natural Gas in Ethanol Plants

c. Ethanol Production Yield

2. Controversy Concerning the Ethanol Energy Balance

B. Overview of Methodology

1. Amount of Conventional Fuel Replaced By Renewable Fuel (R)

2. Lifecycle Impacts of Conventional Fuel Use (LC)

3. Displacement Indexes (DI)

C. Impacts of Increased Renewable Fuel Use

1. Fossil Fuels and Petroleum

2. Greenhouse Gases and Carbon Dioxide

D. Implications of Reduced Imports of Petroleum Products

X. Agricultural Sector Economic Impacts

XI. Public Participation

XII. Administrative Requirements

A. Executive Order 12866: Regulatory Planning and Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

1. Overview

2. Background—Small Refiners Versus Small Refineries

3. Summary of Potentially Affected Small Entities

4. Impact of the Regulations on Small Entities

5. Small Refiner Outreach

6. Conclusions

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer Advancement Act

XIII. Statutory Authority

I. Background

This section describes the required elements of the renewable fuel program, also known as the Renewable Fuel Standard (RFS) program, as stipulated in Section 211(o) of the Clean Air Act (CAA) as amended by the Energy Policy Act of 2005 (the Energy Act or the Act).

A. The Role of Renewable Fuels in the Transportation Sector

Renewable fuels have been an important part of our nation's transportation fuel supply for many years. Following the CAA amendments of 1990, the use of renewables fuels, particularly ethanol, increased dramatically. Several key clean fuel programs required by the CAA established new market opportunities for ethanol. A very successful mobile source control strategy, the reformulated gasoline (RFG) program, was implemented in 1995. This program set stringent new controls on the emissions performance of gasoline, which were designed to significantly reduce summertime ozone precursors and year round air toxics emissions. The RFG program also required that RFG meet an oxygen content standard. Several areas of the country began blending ethanol into gasoline to help meet this new standard, such as Chicago and St. Louis. Another successful clean fuel strategy required certain areas exceeding the national ambient air quality standard for carbon monoxide to also meet an oxygen content standard during the winter time to reduce harmful carbon

monoxide emissions. Many of these areas also blended ethanol during the winter months to help meet this new standard, such as Denver and Phoenix. As a result of these programs, and other factors, currently all areas requiring RFG or winter oxygenated fuels are blending ethanol at some level to support meeting the clean fuel requirements.

Today, the role and importance of renewable fuels in the transportation sector continues to expand. In the past several years as crude oil prices have soared above the lower levels of the 1990's, the relative economics of renewable fuel use has improved dramatically. In addition, since the vast majority of crude oil produced in or imported into the U.S. is consumed as gasoline or diesel fuel in the U.S., concerns about our dependence on foreign sources of crude oil has renewed interest in renewable transportation fuels. The passage of the Energy Policy Act of 2005 demonstrated a strong commitment on the part of U.S. policymakers to consider additional means of supporting renewable fuels as a supplement to petroleum-based fuels in the transportation sector. The RFS program is such a program.

The RFS program was debated by the U.S. Congress over several years before finally being enacted through passage of the Energy Policy Act of 2005. The RFS program is first and foremost designed to increase the use of renewable fuels in motor vehicle fuels consumed in the U.S. In this context, it is expected to simultaneously reduce dependence on foreign sources of petroleum, increase domestic sources of energy, and diversify our energy portfolio to help in moving beyond a petroleum-based economy.

The increased use of renewable fuels such as ethanol and biodiesel is also expected to have the added benefit of providing an expanded market for agricultural products such as corn and soybeans. Based on our analysis, there is also an expectation that the expanded use of renewable fuels will provide reductions in carbon dioxide emissions and air toxics emissions such as benzene from the transportation sector, while other emissions such as hydrocarbons and oxides of nitrogen may increase.

The level of the renewable fuels standard set forth by Congress works in conjunction with other provisions that were enacted as part of the Energy Act. In particular, the level of the renewable fuel standard more than offset the possible loss in demand for renewable fuels occasioned by the Act's repeal of the oxygen content mandate in the reformulated gasoline program while allowing greater flexibility in how renewable fuels were blended into the nation's fuel supply. The renewable fuel standard additionally created a specific annual level for minimum renewable fuel use which increases over time, ensuring overall growth in the demand and opportunity for renewable fuels.

Because renewable fuels such as ethanol and biodiesel are not new to the U.S. transportation sector, the expansion of their use is expected to follow distribution and blending practices already in place. For instance, the market already has the necessary production and distribution mechanisms in place in many areas, and the ability to expand these mechanisms into new markets. Recent spikes in ethanol use resulting first from the state MTBE bans, and now the virtual elimination of MTBE from the marketplace, have tested the limits of the ethanol distribution system. However, future growth is expected to move in a more orderly fashion since the use of renewable fuels will not be geographically constrained and, given EIA volume projections, investment decisions can follow market forces rather than regulatory mandates. In addition, the increased production volumes of ethanol and the expanded penetration of ethanol in new markets may create new opportunities for blending of E85, a blend of 85 percent ethanol and 15 percent gasoline, in the long run. The increased availability of E85 will mean that more flexible fueled vehicles (FFV) can use this fuel. Of the approximately 5 million FFVs currently in use in the U.S, most are currently fueled with conventional gasoline rather than E85, in part due to the limited availability of E85.

Given the ever-increasing demand for petroleum-based products in the transportation sector, the RFS program is an important first step in U.S. efforts to move toward energy independence. The RFS standard provides the certainty that at least a minimum amount of renewable fuel will be used in the U.S., which in turn provides investment certainty for the growth in production capacity of renewable fuels. However, the RFS program is not the only thing impacting demand for ethanol and other renewable fuels. As Congress was developing the RFS program in the Energy Act, several large states were adopting and implementing bans on the use of MTBE in gasoline. As a result, refiners were forced to switch to ethanol to satisfy the oxygen content mandate for their reformulated gasoline in the U.S., causing a large, quick increase in demand for ethanol. Even more importantly, with the removal of the oxygen content mandate for RFG, refiners elected to remove essentially all MTBE from the gasoline supply in the U.S. during the spring of 2006. In order to accomplish this transition quickly, while still maintaining gasoline volume, octane, and gasoline air toxics performance standards, refiners elected to blend ethanol into virtually all reformulated gasoline nationwide. This caused a second dramatic increase in demand for ethanol, which in the near term has been met by temporarily shifting large volumes of ethanol out of conventional gasoline and into the RFG areas. Perhaps the largest impact on renewable fuel demand, however, has been the dramatic increase in the cost of crude oil. In the last few years, both crude oil prices and crude oil price forecasts have increased dramatically. This has resulted in a large economic incentive for the use of ethanol and biodiesel. The Energy Information Administration (EIA) and others are currently projecting renewable fuel demand to exceed the minimum volumes required under the RFS program by a substantial margin. In this context, the statutory goal of the RFS program is to provide an important foundation for ongoing investment in renewable fuel production. However, market demand for renewable fuels is expected to exceed the statutory minimums. We believe we are proposing a program structure that could continue to operate effectively regardless of the level of renewable fuel use or market conditions in the energy sector.

B. Requirements in the Energy Policy Act

Section 1501 of the Energy Policy Act provides the statutory basis for the RFS program. This provision was added to the CAA as Section 211(o). It requires EPA to establish a program to ensure that the pool of gasoline sold in the contiguous 48 states contains specific volumes of renewable fuel for each calendar year starting with 2006. The required overall volumes for 2006 through 2012 are shown in Table I.B-1 below.

Table I.B-1.—Applicable Volumes of Renewable Fuel Under the RFS Program

Calendar year

Billion gallons

2006

4.0

2007

4.7

2008

5.4

2009

6.1

2010

6.8

2011

7.4

2012

7.5

In order to ensure the use of the total renewable fuel volume specified for each year, the Agency must set a standard for each year representing the amount of renewable fuel that a refiner, blender, or importer must use, expressed as a percentage of gasoline sold or introduced into commerce. This yearly percentage standard is to be set at a level that will ensure that the total renewable fuel volumes shown in Table I.B-1 will be used based on gasoline volume projections provided by the Energy Information Administration (EIA). The standard for each year must be published in the

Federal Register

by November 30 of the previous year. Starting with 2013, EPA is required to establish the applicable national volume, based on the criteria contained in the statute, which must require at least the same overall percentage of renewable fuel use as was required in 2012.

Renewable fuels are defined in the Act primarily on the basis of the feedstock. In general, renewable fuels must be a motor vehicle fuel that is produced from plant or animal products or wastes, as opposed to fossil fuel sources. The Act specifically identifies several types of motor vehicle fuels as renewable fuels, including cellulosic biomass ethanol, waste-derived ethanol, biogas, biodiesel, and blending components derived from renewable fuel.

The standard set annually by EPA is to be a single percentage applicable to refiners, blenders, and importers, as appropriate. The percentage standard is used by obligated parties to determine a volume of renewable fuel that they are responsible for ensuring is introduced into the domestic gasoline pool for the given year. The percentage standard must be adjusted such that it does not apply to multiple parties for the same volume of gasoline. The standard must also take into account the fact that small refineries are exempted from the program until 2011, but must take into account the use of renewable fuel by those small refineries.

Under the Act, the required volumes in Table I.B-1 apply to the contiguous 48 states. However, Alaska and Hawaii can opt into the program, in which case the pool of gasoline used to calculate the standard, and the number of regulated parties, would change. In addition, other states can request a waiver of the RFS program under certain conditions, which would affect the national quantity of renewable fuel required under the program.

The Act requires the Agency to promulgate a credit trading program for the RFS program whereby an obligated party may generate credits for over complying with their annual obligation. The obligated party can then use these credits or trade them for use by another obligated party. Thus the credit trading program allows obligated parties to comply in the most cost-effective manner by permitting them to generate, transfer, and use credits. The trading program also permits renewable fuels that are not blended into gasoline, such as biodiesel, to participate in the RFS program.

The Agency must also determine who can generate credits and under what conditions, how credits may be transferred from one party to another, and in certain cases the appropriate value of credits for different types of renewable fuel. If a party is not able to generate or purchase sufficient credits to meet their annual obligation, they are allowed to carry over the deficit to the next annual compliance period, but must achieve full compliance in that following year.

C. Default Standard Applicable to 2006

The Energy Act was enacted in August of 2005 and included provisions for a renewable fuel program that was to begin in January of 2006. We recognized that a rulemaking implementing the full RFS program, including both program design and the various analyses necessary, would require a substantial effort involving many stakeholders. This process was expected to take longer than one year, and as a result we knew it would not be completed in time to be implemented by January of 2006.

The Energy Act anticipated this possibility and specified a default standard applicable for just 2006. The default standard specified that the percentage of renewable fuel in gasoline sold or dispensed to consumers in the U.S. in calendar year 2006 must be 2.78 volume percent.

The default standard would be applicable if the Agency did not promulgate regulations to implement the full RFS program for 2006. Since the full program could not be promulgated during 2006, the default standard of 2.78 percent applies to calendar year 2006.

However, the provision for the default standard in the Act does not provide adequate specificity on how to implement the default standard. For instance, the Act's default standard provision does not specify the liable parties and the specific nature of their obligation. It also does not discuss compliance mechanisms, reporting requirements, or credit generation and use. The resulting uncertainty associated with the default standard would have created confusion and risked a problematic initial implementation of the RFS program.

The default standard of 2.78 percent represented approximately 4.0 billion gallons of renewable fuel.

As a result, the Agency published a rule on December 30, 2005 that interpreted and implemented the default provision, to provide certainty to parties involved in the production and distribution of gasoline and renewable fuels.

In that action, the Agency clarified the default standard for 2006 with regulations identifying the liable parties as refiners, importers, and blenders. The default standard was interpreted as establishing a collective obligation, rather than an individual obligation. Under this interpretation, refiners, blenders, and importers are responsible as a group for meeting the default 2.78 percent standard, and compliance with this standard is calculated over the pool of all gasoline sold to consumers. An individual refiner, blender, or importer is not responsible for meeting the 2.78 percent standard for the specific gasoline it produces. The regulations implementing the default standard for 2006 did not include any provisions for credit generation or trading, given the collective nature of the obligation. However, any shortfall in renewable fuel production in 2006 would be added as a deficit carryover to the standard for 2007. Based on information available to date, this does not appear to be necessary. Total ethanol production in the U.S. exceeded 4.0 billion gallons in 2005 by a small margin, and several hundred million gallons of additional ethanol production capacity has come online in 2006. Thus it is anticipated that the total ethanol production volume and ultimate use in 2006 will be more than sufficient to meet the default standard of 2.78 percent.

Today's proposal outlines the full RFS program, covering all of the provisions required in the Act. It applies in calendar year 2007 and beyond, since the direct final rule described above addresses RFS compliance for 2006 only.

70 FR 77325 (December 30, 2005).

D. Development of the Proposal

The RFS program was prescribed in section 1501 of the Act, including the

required total volumes, the timing of the obligation, the parties who are obligated to comply, the definition of renewable fuel, and the general framework for a credit program. As with many legislative actions, various aspects of the program require additional development by the Agency beyond the specifications in the Act. The credit trading program and related compliance mechanisms are a central aspect of the program, and the Agency is responsible for developing regulations to ensure the successful implementation of the RFS program, based on the framework spelled out in the statute.

Under the RFS program the credit trading provisions will comprise a critical element of compliance. Many obligated parties do not have easy access to renewable fuels or the ability to blend them, and so will rely on the use of credits to comply. The RFS credit program is also unique in that the parties liable for meeting the standard (refiners, importers, and blenders of gasoline) are not generally the parties who make the renewable fuels or blend them into gasoline. This creates the need for trading mechanisms that ensure that the means to demonstrate compliance will be readily available for use by obligated parties.

Given these considerations, the first step we took in developing the proposed program was to seek input and recommendations from the affected stakeholders. There were initially a wide range of thoughts and views on how to design the program. However, there was broad consensus that in the end the program should satisfy a number of guiding principles, including for example that the compliance and trading program should provide certainty to the marketplace and minimize cost to the consumers; that the program should preserve existing business practices for the production, distribution, and use of both conventional and renewable fuels; that the program should be designed to accommodate all qualifying renewable fuels; that all renewable volumes produced are made available to obligated parties for compliance; and finally that the Agency should have the ability to easily verify compliance to ensure that the volume obligations are in fact met. Over the course of several months, these guiding principles helped to move us toward today's proposal.

II. Overview of the Proposal

Today's action describes our proposed requirements for the RFS program, as well as a preliminary assessment of the environmental and economic impacts of the nation's transition to greater use of renewable fuels. This section provides an overview of our proposal and renewable fuel impacts assessment. Sections III through V provide the details of the proposed structure of the program, while Sections VI through X describe our preliminary assessment of the impacts on emissions, air quality, fossil fuel use, and cost resulting from expanded renewable fuel use.

A. Impacts of Increased Reliance on Renewable Fuels

In a typical major rulemaking, EPA would conduct a full assessment of the economic and environmental impacts of the program. However, as discussed in Section I.A., the replacement of MTBE with ethanol and the extremely favorable economics for renewable fuels brought on by the rise in crude oil prices are causing renewable fuel use to far exceed the RFS requirements. This makes an assessment of the program of limited if any utility, given that it is not currently driving real world impacts and future projections by the Energy Information Administration indicate that this favorable condition will continue. Consequently, it is of greater relevance and interest to assess the impacts of this larger increase in renewable use and the related changes occurring to gasoline. For this reason we have carried out an assessment of the economic and environmental impacts of the broader changes in fuel quality resulting from our nation's transition to greater utilization of renewable fuels, as opposed to an assessment of the RFS program itself.

In summary, depending on the volume of renewable fuel assumed to be used in 2012 (7.5 to 9.9 billion gallons), we estimate that this transition to renewable fuels will reduce petroleum consumption by 2.3 to 3.9 billion gallons or approximately 1.0 to 1.6 percent of the petroleum that would otherwise be used by the transportation sector. Carbon monoxide emissions from gasoline powered vehicles and equipment will be reduced by 1.3 to 3.6 percent while emissions of benzene (a mobile source air toxic) will be reduced by 1.7 to 6.2 percent. At the same time, other emissions may increase. Nationwide, we estimate between a 28,000 and 97,000 ton increase in VOC + NO

emissions. However, the effects will vary significantly by region with some major areas like New York City, Chicago and Los Angeles experiencing no increase while other areas may see an increase in VOC emissions from 3 to 5 percent and an increase in NO

emissions from 4 to 6 percent from gasoline powered vehicles and equipment. Furthermore, the use of renewable fuel will reduce CO

equivalent greenhouse gas emissions by 9 to 14 million tons, about 0.4 to 0.6 percent of the anticipated greenhouse gas emissions from the transportation sector in the United States in 2012. On average, we estimate the cost of this increase in renewable fuel to range from 0.3 cents per gallon to 1 cent per gallon of gasoline for the nation as a whole. We anticipate additional impacts that we intend to evaluate as part of the final rulemaking, including changes in renewable fuel feedstock market prices, decreased imports of petroleum, and effects on energy security.

To carry out our analyses, we elected to use 2004 as the baseline from which to compare the impacts of expanded renewable use. We chose 2004 as a baseline primarily due to the fact that all the necessary refinery production data, renewable production data, and fuel quality data was already in hand at the time we needed to begin the analysis. We did not use 2005 as a baseline year because 2005 may not be an appropriate year for comparison due to the extraordinary impacts of hurricanes Katrina and Rita on gasoline production and use. To assess the impacts of anticipated increases in renewable fuels, we elected to look at what they would be in 2012, the year the statutorily-mandated renewable fuel volumes will be fully phased in. By conducting the analysis in this manner, the impacts include not just the impact of expanded renewable fuel use by itself, but also the corresponding decrease in the use of MTBE, and the potential for oxygenates to be removed from RFG due to the absence of the RFG oxygenate mandate. Since these three changes are all inextricably linked and are occurring simultaneously in the marketplace, evaluating the impacts in this manner is appropriate.

We evaluated the impacts of expanded renewable use and the corresponding changes to the fuel supply on fuel costs, consumption of fossil fuels, and some of the economic impacts on the agricultural sector. We also evaluated the impacts on emissions, including greenhouse gas emissions, and the corresponding impacts on nationwide and regional air quality. Our preliminary analyses are summarized in this section. There are a number of uncertainties associated with this preliminary assessment. The analyses described here will be updated for the final rule including additional investigation into these uncertainties.

1. Renewable Fuel Volumes Scenarios Analyzed

As shown in Table I.B-1, the Act stipulates that the nationwide volumes of renewable fuel required under the RFS program must be at least 4.0 billion gallons in 2006 and increase to 7.5 billion gallons in 2012. However, we expect that the volume of renewable fuel will actually exceed the required volumes by a significant margin. Based on economic modeling, EIA projects renewable demand in 2012 of 9.6 billion gallons for ethanol, and 300 million gallons for biodiesel using crude oil prices forecast at $47 per barrel. Therefore, in assessing the impacts of expanded use of renewable fuels, we evaluated two comparative scenarios, one representing the statutorily required minimum, and one reflecting the higher levels projected by EIA. Although the actual renewable fuel volumes produced in 2012 may differ from both the required and projected volumes, we believe that these two volume scenarios together represent a reasonable range for analysis purposes.

The Act also stipulates that at least 250 million gallons out of the total volume required in 2013 and beyond must be cellulosic biomass ethanol. Because we anticipate a ramp-up in production of cellulosic biomass ethanol products in the coming years, we have assumed that 250 million gallons of ethanol in 2012 will come from a cellulosic biomass source. Also, EIA has projected in their economic modeling a biodiesel demand in 2012 of 300 million gallons. Thus for both the required and projected volume scenarios that we evaluated for 2012, we assumed these same production volumes for cellulosic biomass ethanol and biodiesel.

As discussed above, we chose 2004 as our baseline. However, a direct comparison of the fuel quality impacts on emissions and air quality required that changes in overall fuel volume, fleet characterization, and other factors be constant. Therefore, we developed a reference case which represents the fuel volume, fleet characterization, and other factors expected in 2012. Fuel quality was maintained by simply growing ethanol use in equal proportion to growth in gasoline demand through 2012.

A summary of the assumed renewable fuel volumes for the scenarios we compared is shown in Table II.A.1-1.

Table II.A.1.-1—Renewable Fuel Volume Scenarios

[billion gallons]

2004 Base case

2012

Reference case

RFS

required

volume

Projected volume

Corn-ethanol

3.5

3.9

6.95

9.35

Cellulosic ethanol

0.25

Biodiesel

0.025

0.028

0.3

Total volume

3.025

3.928

7.5

9.9

2. Emissions

We evaluated the impacts of increased use of ethanol and biodiesel on emissions and air quality in the U.S. relative to the 2012 reference case. For the nation as a whole, we estimated that summertime VOC and NO

emissions from gasoline and diesel vehicles and equipment would each increase by about 0.5 percent for the 7.5 billion gallon scenario, and by about 1.0 percent for the 9.9 billion gallon scenario. This would be equivalent to between 28,000 and 97,000 tons of VOC + NO

nationwide. However, the effects will vary by region. For instance, for areas in which 10 percent ethanol blends already predominated in 2004, such as New York City, Chicago, and Los Angeles, if they continue to use ethanol at the same levels there will be no impact. However, for conventional gasoline areas in which no ethanol was used in 2004 but which are projected to transition to full use of ethanol in 2012, we estimated that VOC and NO

emissions from gasoline vehicles and equipment would increase by 3-5 percent and 4-6 percent, respectively.

Unlike VOC and NO

, emissions of CO and benzene from gasoline and diesel vehicles and equipment were estimated to decrease when the use of renewable fuels increased. Reductions in emissions of CO varied from as low as 1.3 percent to as high as 3.6 percent for the nation as a whole, depending on both the renewable fuel volume scenario and assumptions regarding the amount of ethanol used in reformulated versus conventional gasoline. Benzene emissions from gasoline vehicles and equipment were estimated to be reduced from 1.7 to 6.2 percent.

We do not have sufficient data to predict the effect of ethanol use on levels of either directly emitted particulate matter (PM) or secondarily formed PM, but do expect a net reduction in ambient PM levels to result due to the secondary PM impacts as discussed in section VIII.C. However, data on direct PM emission impacts is available for biodiesel. We estimate that reductions in emissions of direct PM from the projected increase in the use of biodiesel to be about 100 tons nationwide, equivalent to less than 0.5 percent of the diesel PM inventory.

The emission impact estimates described above are based on the best available data and models. However, it must be highlighted that most of the fuel effect estimates are based on very limited or old data which may no longer be reliable in estimating the emission impacts on vehicles in the 2012 fleet with advanced emission controls.

As such, these emission estimates should be viewed as preliminary. EPA hopes to conduct significant new testing in order to better estimate the impact of fuel changes on emissions from both highway vehicles and nonroad equipment, including those fuel changes brought about by the use of renewable fuels. We hope to be able to incorporate the data from such additional testing into the analyses for other studies required by the Energy Act in 2008 and 2009, and into a subsequent rule to set the RFS program standard for 2013 and later.

Advanced emission controls include close-coupled, high density catalysts and their associated electronic control systems for light-duty vehicles, and NO

adsorbers and PM traps for heavy-duty engines.

We used the Ozone Response Surface Model (RSM) to estimate the impacts of increased use of ethanol on ozone levels for the 7.5 billion gallon use scenario representing the required volumes

under the RFS program. We did not evaluate other renewable fuel volumes scenarios due to the limited amount of time available for completing this NPRM. The ozone RSM approximates the effect of VOC and NO

emissions in a 37-state eastern area of the U.S. Using this model, we projected that the changes in VOC and NO

emissions could produce a very small increase in ambient ozone levels. On average, ozone levels increased by 0.06 ppb, which represents less than 0.1 percent of the standard. Even for areas expected to experience a significant increase in ethanol use, ozone levels increased by only 0.1-0.2 ppb, less than 0.2 percent of the standard. These ozone impacts do not consider the reductions in CO emissions mentioned above, or the change in the types of compounds comprising VOC emissions. Directionally, both of these effects may mitigate these already small ozone increases. The ozone impacts also do not consider the impact of increased emissions from ethanol and biodiesel production facilities or any corresponding decrease in emissions from refineries.

We investigated several other issues related to emissions and air quality that could affect our estimates of the impacts of increased use of renewable fuels. These are discussed in section VIII and in greater detail in the draft Regulatory Impact Analysis (DRIA). For instance, our current models assume that recent model year vehicles are insensitive to many fuel changes. However, a limited amount of new test data suggests that newer vehicles may be just as sensitive as older model year vehicles. Our sensitivity analysis suggests that if this is the case VOC emissions could decrease slightly while NO

would still increase. We also evaluated the emissions from the production of both ethanol and biodiesel fuel and determined that they will also increase with increased use of these fuels. Nationwide, emissions related to the production and distribution of ethanol and biodiesel fuel are expected to be of the same order of magnitude as the emission impacts related to the use of these fuels in vehicles. Finally, a lack of emission data and atmospheric modeling tools prevented us from making specific projections of the impact of renewable fuels on ambient PM levels. However, ethanol use may have an affect on ambient PM levels. Emerging science indicates that aromatic VOC emissions react in the atmosphere to form PM. Increased ethanol use is expected to cause a corresponding reduction in the aromatic content of gasoline, which should reduce aromatic VOC emissions and therefore potentially also impact atmospheric PM levels. All of these issues will be the subject of further study and analysis in the future.

3. Economic Impacts

As discussed in more detail in Section X, for the final rule we also plan to assess a range of economic impacts that could result from the expanded use of renewable fuels. Due to the time required to complete these analyses, we only have preliminary data for some of these impacts available for this proposal.

In Section VII of this preamble, we estimate the cost of producing the extra volumes of renewable fuel anticipated through 2012. For corn ethanol, we estimate the per gallon cost of ethanol to range from $1.20 per gallon in 2012 (2004 dollars) in the case of the 7.2 billion gallons per year case and $1.26 per gallon in the case of the 9.6 billion gallon case. These costs take into account the cost of the feedstock (corn), plant equipment and operation and the value of any co-products (distiller's dried grain and solubles, for example). For biodiesel, we estimate the per gallon cost to be between $1.89 and $2.11 per gallon if produced using soy bean oil, and less if using yellow grease or other relatively low cost or no-cost feedstocks. All of these fuel production costs are without accounting for tax subsidies for these renewable fuels.

We also note that these costs represent the production cost of the fuel and not the market price. In recent years, the prices of ethanol and biodiesel have tended to track the prices of gasoline and diesel, in some cases even exceeding those prices.

Tax subsidies were subtracted out of the cost estimates, but consumer behavior in the absence of these tax subsidies was not modeled.

These renewable feedstocks are then used as blend fuels in gasoline and diesel. While biodiesel is typically just blended with petroleum diesel, additional efforts are sometimes necessary and/or economically advantageous at the refiner level when adding ethanol to gasoline. For example, ethanol's high octane reduces the need for other octane enhancements by the refiner, whereas offsetting the volatility increase caused by ethanol may require removal of other highly volatile components. Section VII examines these fuel cost impacts and concludes that the net cost to society in 2012 in comparison to the reference case of the increased use of renewable fuels and their replacement of MTBE, will range from an estimate of 0.3 cent to 1 cent per gallon of gasoline.

This fuel cost impact does not consider other societal benefits. For example, the petroleum-based fuel displaced by renewable fuel, largely produced in the United States, should reduce our use of imported oil and fuel. We estimate that 95 percent of the lifecycle petroleum reductions resulting from the use of renewable fuel will be met through reductions in net petroleum imports. In Section IX of this preamble we estimate the value of the decrease in imported petroleum at about $3.5 billion in 2012 for the 7.5 billion gallon case and $5.8 billion for the 9.6 billion gallon case, in comparison to our 2012 reference case. Total petroleum import expenditures in 2012 are projected to be about $698 billion.

The above numbers only assess those impacts of increased production and use of renewable fuel that we can quantify at this time. The RFS program attempts to spur the increased use of renewable transportation fuels made principally from agricultural crops produced in the U.S. As a result, it is important to analyze the consequences of the transition to greater renewable fuel use in the U.S. agricultural sector. To analyze the impacts on the U.S. agricultural sector, EPA has selected the Forest and Agricultural Sector Optimization Model (FASOM) developed by Professor Bruce McCarl, Texas A&M University and others over the past thirty years. FASOM is a dynamic, nonlinear programming model of the agriculture and forestry sectors of the U.S. (For this analysis, we will be focusing upon the agriculture portion of the model.) The strength of this model is its consideration of the full direct and indirect impacts of a shift in production of an agricultural commodity. For example, increased ethanol use will increase the demand for corn. The model assesses not only the impacts of increased demand for corn on acres devoted to corn production but also where the incremental corn will be produced, what other crops will be displaced and how corn is allocated among competing uses. Shifts in corn production will likely impact the price of corn and other crop prices. The model can also estimate the impacts of increased renewable fuel use on animal feed costs, animal production, costs to consumers and U.S. agricultural exports. Similarly, FASOM can estimate effects on U.S. farm employment and income (broken down by region, and farm sector such as corn farmers versus soybean producers versus the livestock industry, for example).

One of the effects of increased use of renewable fuel is that it diversifies the energy sources used in making transportation fuel. To the extent that diverse sources of fuel energy reduce the dependence on any one source, the risks, both financial as well as strategic, of potential disruption in supply or spike in cost of a particular energy source is reduced. As part of the RFS rulemaking, EPA is estimating the energy security effects of reduced oil use due to the expanded use of renewable fuel. However, these analyses will not be available until the final rule.

4. Greenhouse Gases and Fossil Fuel Consumption

There has been considerable interest in the impacts of fuel programs on greenhouse gases and fossil fuel consumption. Therefore, in this proposed rulemaking we have undertaken an analysis of the greenhouse gas and fossil fuel consumption impacts of a transition to greater renewable fuel use. This is the first analysis of its kind in a major rule, and as such it may guide future work in this area.

As a result of the transition to greater renewable fuel use, some petroleum-based gasoline and diesel will be directly replaced by renewable fuels. Therefore, consumption of petroleum-based fuels will be lower than it would be if no renewable fuels were used in transportation vehicles. However, a true measure of the impact of greater use of renewable fuels on petroleum use, and indeed on the use of all fossil fuels, accounts not only for the direct use and combustion of the finished fuel in a vehicle or engine, but also includes the petroleum use associated with production and transportation of that fuel. For instance, fossil fuels are used in producing and transporting renewable feedstocks such as plants or animal byproducts, in converting the renewable feedstocks into renewable fuel, and in transporting and blending the renewable fuels for consumption as motor vehicle fuel. Likewise, fossil fuels are used in the production and transportation of petroleum and its finished products. In order to estimate the true impacts of increases in renewable fuel use on fossil fuel use, we must take these steps into account. Such analyses are termed lifecycle analyses.

We compared the lifecycle impacts of renewable fuels to the petroleum-based gasoline and diesel fuels that they replace. This analysis allowed us to estimate not only the overall impacts of renewable fuel use on petroleum use, but also on emissions of greenhouse gases such as carbon dioxide from all fossil fuels. Based on a comparison to the 2004 base fuel, we estimated that the increased use of renewable fuels will reduce petroleum consumption by about 1.0 to 1.6 percent in the transportation sector in 2012. This is equivalent to 2.3-3.9 billion gallons of petroleum in 2012. We also estimated that greenhouse gases from the transportation sector will be reduced by about 0.4-0.6 percent, equivalent to about 9-14 million tons. These reductions are projected to continue to increase in the future as crude oil prices are expected to continue to provide the stimulus for greater use of renewable fuels beyond 2012. These greenhouse gas emission reductions are also dominated by the forecast that the majority of the future ethanol use will be produced from corn. If advances in cellulosic technology allow its use to exceed the levels assumed in our analysis, then even greater greenhouse gas reductions would result.

Cellulosic ethanol is estimated to provide a comparable petroleum displacement as corn derived ethanol on a per gallon basis, though the impacts on total energy and greenhouse gas emissions differ.

5. Potential Water Quality Impacts

Expansion in the use of renewable fuels will also have other important impacts which should be the focus of further study and evaluation. In particular, renewable fuels such as ethanol and biodiesel produced from agricultural feedstocks raise important issues with respect to the water quality impacts resulting from the increased production of corn and soybeans. Due to competing demand, which includes livestock producers, sweetener manufacturers, and foreign buyers among others, it is extremely unlikely that the current corn crop would be devoted to ethanol production. USDA's Economic Research Service predicts that current demand for feed and exports are expected to stay constant or perhaps rise.

Additional corn-based ethanol production would have to come from increased corn yields, increased acreage, and switching acreage to corn production from other crops like soybeans and cotton.

“USDA Agricultural Baseline Projections To 2015,” February 2006, Economic Research Service.

For more discussion of agricultural sector effects, see Section IX.

Changes in agriculture as a result of increased use of renewable fuels can have significant adverse effects upon water quality, either locally or on a more broad basis. This has the potential to lead to increased runoff and delivery to water bodies of nutrients, pesticides and sediments, as well as increased salinity of farmland resulting from increased irrigation. The increased runoff of nutrients in turn can cause eutrophication of small water bodies as a result of localized runoff or large water bodies as a result of increased regional runoff such as currently occurs in the creation of the hypoxic zone in the Gulf of Mexico, or eutrophication in the Chesapeake Bay. Some lands have been retired (

e.g.

, under the Farm Bill's Conservation Reserve Program, or simply at the land-owner's initiative) because those lands are highly erosive, steep, or adjacent to water bodies. Therefore, farming these lands without appropriate mitigation measures would pose a particularly great risk to water quality and threaten to erase some of the gains of the last 20 years of Farm Bill and Clean Water Act implementation. Note that there may be similar environmental implications in other countries depending on the extent that either imports of renewable fuels or exports of agricultural commodities such as corn are affected.

We have not conducted an analysis for this proposal of the impacts on water quality that might result from the increased use of renewable fuels. However, this impact could present important public policy issues as renewable use expands, with examination required of both the possible benefits and detriments.

B. Program Structure

The RFS program proposed today requires refiners, importers, and blenders (other than oxygenate blenders) to show that a required volume of renewable fuel is used. The required volume is determined by multiplying their annual gasoline production by a percentage standard specified by EPA. Compliance is demonstrated through the acquisition of unique Renewable Identification Numbers (RINs) assigned by the producer to every batch of renewable fuel produced. The RIN shows that a certain volume of renewable fuel was produced. Each year, the refiners, blenders and importers obligated to meet the renewable volume requirement (referred to as “obligated parties”) must acquire sufficient RINs to demonstrate compliance with their volume obligation. RINs can be traded in the same manner as the credits envisioned in the Act. A system of recordkeeping and electronic reporting for all parties that have RINs ensures the integrity of the RIN pool. This RIN-based system would both meet the requirements of the Act and provide several other important advantages:

• Renewable fuel production volumes can be easily verified.

• RIN trading can occur in real time as soon as the renewable fuel is produced rather than waiting to the end of the year when an obligated party would determine if it had exceeded the standard.

• Renewable fuel can continue to be produced, distributed, and blended in those markets where it is most economical to do so.

• Instances of double-counting of renewable fuel claimed for compliance purposes can be identified based on electronically reported data.

Our proposed RIN-based trading program will be an essential component of the RFS program, ensuring that every obligated party can comply with the standard while providing the flexibility for each obligated party to use renewable fuel in the most economical ways possible.

1. What Is the RFS Program Standard?

EPA is required to convert the aggregate national volumes of renewable fuel specified in the Act into corresponding renewable fuel standards expressed as a percent of gasoline production. The renewable volume obligation that would apply to an obligated party would then be determined based on this percentage and the total gasoline production or import volume in a calendar year, January 1 through December 31. EPA will publish the percentage standard in the

Federal Register

each November for the following year based on the most recent EIA gasoline demand projections. However, since this rulemaking will not be finalized prior to November, 2006, we are proposing in this notice that the standard for 2007 be 3.71 percent. Section III.A describes the calculation of the standard.

2. Who Must Meet the Standard?

Under our proposal, any party that produces gasoline for consumption in the U.S., including refiners, importers, and blenders (other than oxygenate blenders), would be subject to a renewable volume obligation that is based on the renewable fuel standard. These obligated parties would determine the level of their obligation by multiplying the percentage standard by their annual gasoline production volume. The result would be the renewable fuel volume which each party must ensure is blended into gasoline consumed in the U.S., with credit for certain other renewable fuels that are not blended into gasoline. EPA will publish the percentage standard for a year by November of the preceding year.

For 2007, we are proposing that the renewable fuel volume obligation be etermined by multiplying the percentage standard by the volume of gasoline produced or imported prospectively from the effective date of the final rule until December 31, 2007. As discussed in Section III.A.3, we considered and are seeking comment on several other approaches for compliance in 2007, but believe this approach is most appropriate given the circumstances. We are also confident that the total volume of renewable fuel used in 2007 will still exceed the volume specified in the Act.

In determining their annual gasoline production volume, obligated parties would include all of the finished gasoline which they produced or imported for use in the contiguous 48 states, and would also include renewable blendstock for oxygenate blending (RBOB), and conventional blendstock for oxygenate blending (CBOB). Blenders would count as their gasoline production only the volumes of blendstocks added to finished or unfinished gasoline. Renewable fuels blended into gasoline by any party would not be counted as gasoline for the purposes of calculating the annual gasoline production volume.

Small refiners and small refineries would be exempt from meeting the renewable fuel requirements through 2010. All gasoline producers located in Alaska, Hawaii, and noncontiguous U.S. territories would be exempt indefinitely. However, if Alaska, Hawaii or a noncontiguous territory opted into the RFS program, all of the refiners (except for small refiners and refineries), importers, and blenders located in the state would be subject to the renewable fuel standard.

Section III.A provides more details on the standard that must be met, while Section III.C describes the parties that are obligated to meet the standard.

3. What Qualifies as a Renewable Fuel?

We have designed the proposal flexibly to cover the range of renewable fuels produced today as well as any that might be produced in the future, so long as they meet the Act's definition of renewable fuel and have been registered and approved for use in motor vehicles. In this manner, we believe that the proposed program will provide the greatest possible encouragement for the development, production, and use of renewable fuels to reduce our dependence on petroleum. In general, renewable fuels must be produced from plant or animal products or wastes, as opposed to fossil fuel sources. Valid renewable fuels would include ethanol made from starch seeds, sugar, or cellulosic materials, biodiesel (mono-alkyl esters), non-ester renewable diesel, and a variety of other products. Both renewable fuels blended into conventional gasoline or diesel and those used in their neat (unblended) form as motor vehicle fuel would qualify. Section III.B provides more details on the renewable fuels that would be allowed to be used for compliance with the standard under our proposal.

4. Equivalence Values of Different Renewable Fuels

One question that EPA faced in developing the program was what value to place on different renewable fuels and on what basis should that value be determined. The Act specifies that each gallon of cellulosic ethanol be treated as if it were 2.5 gallons of renewable fuel, but does not specify the values for other renewable fuels. As discussed in Section III.B.4., we considered and are seeking comment on a range of options including straight volume, energy content, and life cycle energy or greenhouse gas emissions. However, we are proposing that the “Equivalence Values” for the different renewable fuels be based on their energy content in comparison to the energy content of ethanol, and adjusted as necessary for their renewable content. The result is an Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, for non-ester renewable diesel of 1.7, and for cellulosic ethanol of 2.5. The proposed methodology can be used to determine the appropriate Equivalence Value for any other potential renewable fuel as well.

5. How Will Compliance Be Determined?

Under our proposed program, every gallon of renewable fuel produced or imported into the U.S. would be assigned a unique renewable identification number (RIN). A block of RINs could be assigned to any batch of renewable fuel that is valid for compliance purposes under the RFS program. These RINs would be placed on product transfer documents (PTD) as a batch of renewable fuel is transferred through the distribution system. Once the renewable fuel is obtained by an obligated party or actually blended into a motor vehicle fuel, the RIN could be separated from the batch of renewable fuel to which it had been assigned, and then either used for compliance purposes or traded. For excess RINs

resulting from the production of renewable fuels with Equivalence Values greater than 1.0, the producer of the renewable fuel could retain them for marketing separately (they need not be assigned to a batch of renewable fuel and placed on PTDs).

RINs would represent proof of production which is then taken as proof of consumption as well, since all renewable fuel produced or imported will be either consumed as fuel or exported. For instance, ethanol produced for use as motor vehicle fuel is denatured specifically so that it can only be used as fuel. Similarly, biodiesel is produced only for use as fuel and has no other potential uses. An obligated party would demonstrate compliance with the renewable fuel standard by accumulating sufficient RINs to cover their individual renewable fuel volume obligation. It would not matter whether the obligated party used the renewable fuel themselves. A party's obligation would be to ensure that a certain amount of renewable fuel was used, whether by themselves or by someone else, and the RIN would be evidence that this occurred for a certain volume of renewable fuel. Exporters of renewable fuel would also be required to retire RINs in sufficient quantities to cover the volume of renewable fuel exported. RINs claimed for compliance purposes would thus represent renewable fuel actually consumed as motor vehicle fuel in the U.S.

RINs would be valid for compliance purposes for the calendar year in which they were generated, or the following calendar year. This approach to RIN life would be consistent with the Act's prescription that credits be valid for compliance purposes for 12 months as of the date of generation. An obligated party could either use RINs to demonstrate compliance, or could transfer RINs to any other party. If an obligated party was not able to accumulate sufficient RINs for compliance in a given year, it could carry a deficit over to the next year so long as the full deficit and obligation were covered in the next year.

In order to ensure that previous year RINs are not used preferentially for compliance purposes in a manner that would effectively circumvent the limitation that RINs be valid for only 12 months after the year generated, we are proposing to place a cap on the use of RINs generated the previous year when demonstrating compliance with the renewable volume obligation for the current year. The cap would mean that no more than 20% of the current year obligation could be satisfied using RINs from the previous year. In this manner there is no ability for excess renewable fuel use in successive years to cause an accumulation of RINs from excess compliance in prior years to significantly depress renewable fuel demand in any future year. In keeping with the Act, excess RINs not used would expire.

Section III.D provides more details on how obligated parties would use RINs for compliance purposes.

6. How Would the Trading Program Work?

Renewable fuel producers and importers would be required to generate RINs when they produce or import a batch of renewable fuel. They would then be required to transfer those RINs along with the renewable fuel batches that they represent whenever they transfer the batch to another person. Likewise any other party that takes ownership or custody of the batch would be required to transfer the RIN with the batch. The RIN could be separated from the batch only by obligated parties (at the point when they take ownership of the batch) or a party that converts the renewable fuel into motor vehicle fuel (such as through blending with conventional gasoline or diesel).

Once a RIN is separated from the batch of renewable fuel that it represents, it can be used for compliance purposes, banked, or traded to another party. Separated RINs could be transferred to any party any number of times. Recordkeeping and reporting requirements would apply to any party that holds RINs, whether through the ownership or custody of a batch of renewable fuel or through the transfer of separated RINs.

Thus obligated parties could acquire RINs directly through the purchase of renewable fuel with assigned RINs, or through the open market for RINs that would be allowed under this proposal. Section III.E provides more details on how our proposed RIN trading program would work.

7. How Would the Program be Enforced?

As in all EPA fuel regulations, there would be a system of registration, recordkeeping, and reporting requirements for obligated parties, renewable producers (RIN generators), as well as any parties that procure or trade RINs either as part of their renewable purchases or separately. In most cases, the recordkeeping requirements are not expected to be significantly different from what these parties might be doing already as a part of normal business practices. The lynch pin to the compliance program, however, is the unique RIN number itself coupled with an electronic reporting system where RIN generation, RIN use, and RIN transactions would be reported and verified. Thus, EPA, as well as industry could have confidence that invalid RINs are not generated and that there is no double counting.

C. Voluntary Labeling Program

EPA is considering whether voluntary program options to encourage adoption and use of practices that minimize environmental concerns which may arise with the production of renewable fuels are appropriate. Renewable fuels present a number of environmental advantages as explained elsewhere in the rulemaking package. However, to assure maximum advantage we also need to acknowledge the potential adverse environmental impacts that could arise from the production of renewable fuel and invite consideration of ways of offsetting these potential adverse impacts.

While in other areas of this document we focus on general impacts on air emissions, we also recognize that individual farming and fuel production operations can contribute to air and water pollution if appropriate practices and/or controls are not adopted. Increased production of renewable fuel may result in more intensive use of crop lands and perhaps the addition of crop land acres to meet the expanding need for renewable feed stocks. Such trends could have an adverse impact on, for example, local water quality. Similarly in the case of fuel production facilities, a range of design and operation options could result in varying levels of energy use and air and water pollution.

EPA is considering what voluntary program(s) can be put into place that would encourage farming and fuel production practices to minimize concerns that expanded production of renewable fuel in the United States is likely to result in adverse environmental impacts such as those identified above.

One option could be a voluntary labeling program which would make use of the RIN program proposed in this rulemaking. Under this concept, fuel producers which use best practices would have the option of adding a “G” (for “green”) to the end of the RIN of a fuel to indicate that a gallon of renewable fuel was produced with the combination of best farming practices, and environmentally friendly production methods and facilities. The details of such a concept, including the points noted below, would need to be developed before it could be fully considered for adoption.

At this time, we are requesting comments on voluntary programs that would recognize the efforts of farmers and renewable fuel producers that undertake the most environmentally sound practices and encourage others to adopt similar practices. In particular we are interested in comments on options for designs of potential voluntary programs including what criteria should be used to establish environmentally sound practices, how to verify that these environmental practices are indeed used in the production of renewable fuel, how this information could be used to promote expanded use of good practices, how the program could be most efficiently and effectively administered whether by EPA, some other Federal agencies, or perhaps a third-party, and finally how to assess effectiveness of such a voluntary program.

III. Complying With the Renewable Fuel Standard

According to the Energy Act, the RFS program places obligations on individual parties such that the renewable fuel volumes shown in Table I.B-1 are actually used as motor vehicle fuel in the U.S. each year. To accomplish this, the Agency must calculate and publish a standard by November 30 of each year which is applicable to every obligated party. On the basis of this standard each obligated party determines the volume of renewable fuel that it must ensure is consumed as motor vehicle fuel. In addition to setting the standard, we must clarify who the obligated parties are and what volumes of gasoline are subject to the standard. Obligated parties must also know which renewable fuels are valid for RFS compliance purposes, and how much credit each type of renewable fuel will receive. This section discusses how the annual standard is determined and which parties and volumes of gasoline would be subject to the proposed requirements.

Because renewable fuels are not produced or distributed evenly around the country, some obligated parties will have easier access to renewable fuels than others. As a result, compliance with the RFS program requirements will depend heavily on a credit trading program. This section also describes all the elements of our proposed credit trading program.

A. What Is the Standard That Must Be Met?

1. How Is the Percentage Standard Calculated?

Table I.B-1 shows the required total volume of renewable fuel specified in the Act for 2007 through 2012. The renewable fuel standard is based primarily on (1) the 48-state gasoline consumption volumes projected by EIA as the Act exempts Hawaii and Alaska, subject to their right to opt-in, as discussed in Section III.C.4, and (2) the volume of renewable fuels required by the Act for the coming year. The renewable fuel standard will be expressed as a volume percentage of gasoline sold or introduced into commerce in the U.S., and would be used by each refiner, blender or importer to determine their renewable volume obligation. The applicable percentage is set so that if each regulated party meets the renewable volume obligation based on this percentage then the total amount of renewable fuel used is expected to meet the total renewable fuel volume specified in Table I.B-1.

In determining the applicable percentage for a calendar year, the Act requires EPA to adjust the standard to prevent the imposition of redundant obligations on any person and to account for the use of renewable fuel during the previous calendar year by exempt small refineries, defined as refineries that process less than 75,000 bpd of crude oil. As a result, in order to be assured that the percentage standard will in fact result in the volumes shown in Table I.B-1, several adjustments to what is otherwise a simple calculation must be made.

As stated, the renewable fuel standard for a given year is basically the ratio of the amount of renewable fuel specified in the Act for that year to the projected 48-state non-renewable gasoline volume for that year. While the required amount of total renewable fuel for a given year is provided by the Act, EPA is required to use an EIA estimate of the amount of gasoline that will be sold or introduced into commerce for that year. The level of the percentage standard would be further reduced if Alaska, Hawaii, or a U.S. territory chose to participate in the RFS program, as gasoline produced in or imported into those states or territories would then be subject to the standard. Should any of these states or territories choose to opt into the RFS program, the projected gasoline volume would increase above that consumed in the 48 contiguous states. EIA has indicated that the best estimation of the coming year's gasoline consumption is found in Table 5a (U.S. Petroleum Supply and Demand: Base Case) of the October issue of the monthly EIA publication Short-Term Energy Outlook which publishes quarterly energy projections. Since the October 2006 document is not currently available for the purpose of proposing the 2007 standard and projecting the 2008 and later standards, we have used the gasoline volume projections in EIA's 2006 Annual Energy Outlook (AEO), Table A2 “Energy Consumption by Sector and Source.” We intend to use the October 2006 Short-Term Energy Outlook values for the final rule.

However, these gasoline volumes include renewable fuel use, which in the coming years is expected to be mostly ethanol. As discussed below in Section III.C.1, the renewable fuel obligation will not apply to renewable blenders. Thus, the gasoline volume used to determine the standard must be the non-renewable portion of the gasoline pool, in order to achieve the volumes of renewables specified in the Act. In order to get a total non-renewable gasoline volume, the renewable fuel volume must be subtracted from the total gasoline volume. EIA has indicated that the best estimation of the coming year's renewable fuel consumption is found in Table 11 (U.S. Renewable Energy Use by Sector: Base Case) of the October issue of the monthly EIA publication Short-Term Energy Outlook. For the purpose of proposing the 2007 standard and projecting the 2008 and later standards, we have used the renewable (ethanol) volume projections in EIA's 2006 Annual Energy Outlook (AEO), Table 17 “Renewable Energy Consumption by Sector and Source.” As for the gasoline projections discussed above, we intend to use the October 2006 renewable fuel values for the final rule.

The Act exempts small refineries

from the RFS requirements until the 2011 compliance period. As discussed in Section III.C.3.a, EPA is proposing to also exempt small refiners

from the RFS requirements until 2011, and to treat small refiner gasoline volumes the same as small refinery gasoline volumes. Since small refineries and small refiners would be exempt from the program until 2011, EPA is proposing that their gasoline volumes be excluded from the overall non-renewable gasoline

volume used to determine the applicable percentage. EPA believes this is appropriate because the percentage standard should be based only on the gasoline subject to the renewable volume obligation. This would only occur though the 2010 compliance period when the exemption ends. Calculation of the standard for calendar year 2011 and beyond would include small refinery and small refiner volumes.

Under the Act, small refineries are those with 75,000 bbls/day or less average aggregate daily crude oil throughput.

Small refiners are those entities who produced gasoline from crude oil in 2004, and who meet the crude processing capability (no more than 155,000 barrels per calendar day, bpcd) and employee (no more than 1500 people) criteria as specified in previus EPA fuel regulations.

As discussed above, calculation of the standard requires projections of gasoline use for the upcoming compliance period. EIA does not project small refinery or small refiner gasoline volumes, so other methods of estimating these values are necessary. EPA receives gasoline production data as a part of its fuel programs' reporting requirements that could be used for this purpose. However, since we do not receive the data until late February, the most recent complete annual data set available would be from two years earlier. Given this, the fact that this adjustment is only needed for 4 years, and because the total small refinery and small refiner gasoline production volume is expected to be fairly constant compared to total U.S. gasoline production during this period, we are proposing to estimate small refinery and small refiner gasoline volumes using a constant percentage of national consumption. This percentage would be based on the most recent small refinery and small refiner gasoline data available in time for the final rule. Using information from gasoline batch reports submitted to EPA, EIA data and input from the California Air Resources Board regarding California small refiners, we have estimated this percentage to be 13.5%.

EPA requests comments on this method of estimating small refinery and small refiner gasoline volumes.

“Calculation of the Small Refiner/Small Refinery Fraction for the Renewable Fuel Program,” memo to the docket from Christine Brunner, ASD, OTAQ, EPA, September 2006.

The Act requires that the small refinery adjustment also account for renewable fuels used during the prior year by small refineries that are exempt and do not participate in the RFS program. Accounting for this volume of renewable fuel would reduce the total volume of renewable fuel use required, and thus directionally would reduce the percentage standard. However, there would be no available data on which to base such an adjustment. Furthermore, EPA believes that the amount of renewable fuel that would qualify (i.e., that was used by exempt small refineries and small refiners but not used as part of the RFS program) would be very small. In light of the total volume of renewable fuel required and the precision in which the statute specifies this total volume, the very small volume at issue here would not change the resulting percentage. Under the proposal, small refineries and small refiners are merely treated as any other renewable blender until 2011. Consequently, whatever renewables they blend will be reflected as RINs available in the market, and thus should not be accounted for in the equation used to determine the standard. Therefore, EPA is proposing to assume this value to be zero.

We are proposing that the amount of renewable fuel used in Alaska, Hawaii, or U.S. territories would not affect the amount of renewable fuel required nationwide. We believe this approach is appropriate because the Act requires that the renewable fuel be consumed in the contiguous 48 states unless Alaska, Hawaii, or a U.S. territory opt-in. Additionally, renewable fuel produced in Alaska, Hawaii, and U.S. territories is unlikely to be transported to the contiguous 48 states, and vice versa. Thus, including their renewable fuel volumes in the calculation of the standard would not serve the purpose intended by the Act of ensuring that the statutorily required renewable fuel volumes are consumed in the 48 contiguous States.

A final issue that could affect the calculated value of the standard is any deficit carryover from 2006. Any deficit carryover from 2006 would increase the standard only for 2007. Since renewable fuel use in 2006 is expected to exceed the 2.78 percent default standard, we are proposing that no deficit be carried over to 2007. Beginning with the 2007 compliance period, when annual individual party compliance replaces collective compliance, any deficit is calculated for an individual party and is included in the party's Renewable Volume Obligation (RVO) determination, as discussed in Section III.A.4.

In summary, in order to get the total projected non-renewable gasoline volumes from which to calculate the standard, EPA is proposing to use EIA projections of nationwide and state gasoline consumption, and small refinery and small refiner volumes estimated as a constant percentage of national gasoline volumes.

Based on the discussion above, the formula which we are proposing to be used for calculating the percentage standard is shown below:

EP22SE06.000

Where:

RFStd

= Renewable Fuel standard in year i, in percent

RFV

= Nationwide annual volume of renewable fuels required by section 211(o)(2)(B) of the Act for year i, in gallons

= Amount of gasoline projected to be used in the 48 contiguous states, in year i, in gallons

= Amount of renewable fuel blended into gasoline that is projected to be consumed in the 48 contiguous states, in year i, in gallons

= Amount of gasoline projected to be used in Alaska, Hawaii, or a U.S. territory in year i if the state or territory opts-in, in gallons

= Amount of renewable fuel blended into gasoline that is projected to be consumed in Alaska, Hawaii, or a U.S. territory in year i if the state or territory opts-in, in gallons

= Amount of gasoline projected to be produced by exempt small refineries and small refiners in year i, in gallons (through 2010 only)

Cell

= Beginning in 2013, the amount of renewable fuel that is required to come from cellulosic sources, in year i, in gallons (250,000,000 gallons minimum)

As described in III.B.4.b, we are not proposing regulations that would specify the criteria under which a state could petition the EPA for a waiver of the RFS requirements, nor the ramifications of Agency approval of such a waiver in terms of the level or applicability of the standard. As a result, the proposed formula for the standard shown above does not include any components to account for Agency approval of a state petition for a waiver of the RFS requirements.

EPA is proposing the following formula for calculating the cellulosic

standard that is required beginning in 2013:

EP22SE06.001

Where, except for RFCell

, the variable descriptions are as discussed above. The definition of RFCell

is proposed as:

RFCell

= Renewable Fuel Cellulosic Standard in year i, in percent

EPA requests comments on the components of both of the proposed formulas, and on how the values for the components should be obtained.

2. What Are the Applicable Standards?

EPA will set the percentage standard for each upcoming year based on the most recent EIA projections, and using the other sources of information as noted above. EPA will publish the standard in the

Federal Register

by November 30 of the preceding year. We are proposing the standard for 2007 and estimating the standard for later years based on current information using the formulas discussed above. The standards would be used to determine the renewable volume obligation based on an obligated party's total gasoline production or import volume in a calendar year, January 1 through December 31. The percentage standards do not apply on a per gallon basis. An obligated party will calculate its Renewable Volume Obligation (discussed in Section III.A.4) using the annual standard.

For illustrative purposes, we have estimated the standards for 2007 and later based on current information using the formulas discussed above.

These values are listed below in Table III.A.2-1. The values of the variable RFV are the required renewable fuel volumes specified in the Act (and shown in Table I.B-1). The projected gasoline and renewable fuels volumes were determined from EIA's energy projections. Variables related to state or territory opt-ins were set to zero since we do not have any information related to their participation at this time. Small refinery and small refiner gasoline volumes were calculated based on our proposed method of assuming a constant percentage relative to projected nationwide gasoline. As mentioned earlier, we estimate the small refinery and small refiner fraction to be 13.5%. The exemption for small refineries and small refiners ends at the end of the 2010 compliance period. The deficit for 2006 (applicable to the 2007 standard) was assumed to be zero.

“Calculation of the Renewable Fuel Standard,” memo to the docket from Christine Brunner, ASD, OTAQ, EPA, September 2006.

Table III.A.2-1.—Projected Standards

Year

Standard

Cellulosic standard

2007

3.71%

Not applicable.

2008

4.22%

Not applicable.

2009

4.72%

Not applicable.

2010

5.21%

Not applicable.

2011

4.82%

Not applicable.

2012

4.85%

Not applicable.

2013+

4.70% min. (non-cellulosic)

0.16% min.

For calendar year 2013 and thereafter, the applicable volumes are to be determined in accordance with separate statutory provisions that include EPA coordination with the Departments of Agriculture and Energy, and a review of the program during calendar years 2006 through 2012. The Act specifies that this review consider the impact of the use of renewable fuels on the environment, air quality, energy security, job creation, and rural economic development, and the expected annual rate of future production of renewable fuels, including cellulosic ethanol. We intend to conduct another rulemaking as we approach the 2013 timeframe that would include our review of these factors. This rulemaking would present our conclusions regarding the appropriate applicable volume of renewable fuel for use in calculating the renewable fuel standard for 2013 and beyond. However, at a minimum we expect that the sum of the cellulosic and non-cellulosic standards for 2013 will be no lower than the 2012 standard. Until such time as we conduct that rulemaking, the program proposed by this rule would continue to apply after 2012.

Prior to 2013, the Act specifies that cellulosic biomass ethanol or waste derived ethanol will be considered equivalent to 2.5 gallons of renewable fuel when determining compliance with the renewable volume obligation. As discussed in Section III.D below, a batch's RIN would indicate whether it was cellulosic or non-cellulosic ethanol. Beginning in 2013, the 2.5 to 1 ratio no longer applies for cellulosic biomass ethanol. In its place, the Act requires that the applicable volume of required renewable fuel specified in Table I.B-1 include a minimum of 250 million gallons that are derived from cellulosic biomass. As shown in Table III.A.2-1 above, we have estimated this value (250 million gallons) as a percent of an obligated party's production for 2013. Thus, an obligated party would be subject to two standards in 2013 and beyond, a non-cellulosic standard and a cellulosic standard.

3. Compliance in 2007

The Energy Act requires that EPA promulgate regulations to implement the RFS program, and if EPA did not issue such regulations then a default standard for renewable fuel use would apply in 2006. As described in Section I.C, we promulgated a direct final rule to interpret and implement the application of the statutory default standard of 2.78 percent in calendar year 2006. However, the Act provides no default standard for any other year. Instead, the regulations we promulgate are required to address renewable fuel usage, including calendar year 2007. The program we are proposing today will therefore apply in 2007. While we plan to promulgate the final rule as soon after today's proposal as possible, it will likely not be effective by January 1, 2007. Therefore, our proposal must address how, and for what time periods, the applicable standard and other program requirements will apply to regulated parties for gasoline produced during 2007.

We have identified several options for 2007 compliance. One option would be to extend the collective compliance approach used for 2006 to 2007. Although the Act contains no default

standard applicable to 2007, under this approach we would apply the renewable fuel standard that we calculate for 2007 to obligated parties on a collective basis rather than on an individual basis. Under this approach, no individual facility or company would be liable for meeting the applicable standard. At the end of 2007 we would determine if the industry as a whole had met the standard on average, and any deficit would be carried over into 2008. This approach would be essentially equivalent to deferring the start of the program to 2008, but with the addition of an industry-wide deficit carryover provision. Current projections from the Energy Information Administration (EIA) on the volume of renewable fuel expected to be produced in 2007 indicate that an industry-wide deficit carryover would most likely be unnecessary under this collective compliance approach.

However, given the requirements of the Act, we do not believe that a collective compliance approach is appropriate for 2007. The Energy Act requires us to promulgate regulations that provide for the generation of credits by any person who overcomplies with their obligation. It also stipulates that a person who generates credits must be permitted to use them for compliance purposes, or to transfer them to another party. These credit provisions have meaning only in the context of an individual obligation to meet the applicable standard. Delaying a credit program until 2008 would mean the credit provisions have no meaning at all for 2007.

A variation of the collective compliance approach would add a credit carryover provision in which any excess renewable fuel produced on an industry-wide basis in 2007 would be subtracted from the required volume in the calculation of the applicable 2008 standard. However, under a collective compliance approach, such a credit carryover provision would not meet the statutory requirement since no individual companies could generate, bank, or trade credits. Therefore we do not believe that a collective compliance approach is appropriate.

Another option for 2007 compliance would be for obligated parties to calculate their renewable fuel obligation based on all gasoline volumes produced at any time during the calendar year, regardless of when in 2007 the final rule is published or becomes effective (i.e., the calculation of the renewable volume obligation looks back retroactively to the beginning of the year for gasoline production). Compliance would be determined based on a whole calendar year's production of gasoline, and the compliance determination would not be required until calendar year 2007 was over, after the final rule was published. Obligated parties would know the proposed standard based on today's action, and all regulated parties would likewise know the proposed provisions for recordkeeping, RIN generation and assignment, etc. On this basis they could begin the process of generating RINs and tracking batches of renewable fuel prior to the publication of the final rule. However, it might not be appropriate to apply the standard to all gasoline produced in 2007 unless the regulatory provisions in today's proposal are very similar to those in the final rule. Otherwise, obligated parties and renewable fuel producers would not have adequate lead-time.

For this approach to be effective, renewable producers would have to begin placing RINs on their PTDs at the start of the year 2007 even though the regulations are not yet final. If they do not, then there could be a shortage of RINs available for obligated parties to use for compliance by the end of the year. Since there is no guarantee that renewable fuel producers would generate RINs appropriate prior to adoption of the regulations, another option would be for the Agency to finalize just those RIN-related provisions prior to the end of 2006 that are critical to measuring and tracking batches of renewable fuel and the assignment of RINs to those batches. However, in practice this approach would be little different than finalizing the full rulemaking. As a result we do not believe that this would be a viable option given the time available.

Finally, given the challenges and shortcomings inherent in the other options, we could simply apply the renewable fuel standard to only those volumes of gasoline produced after the effective date of the final rule. Essentially the renewable volume obligation for 2007 would be based on only those volumes of gasoline produced or imported by an obligated party prospectively from the effective date of the rulemaking forward, and renewable producers would not have to begin generating RINs and maintaining the necessary records until this same date. As a result, such an approach would be relatively straightforward to implement, provide the industry with the certainty they need to comply, and give them time to put in place their compliance plans and actions. It also would be unlikely to have any negative impacts on renewable fuel use given the expectations that total volumes in 2007 will exceed the national volume required for 2007. This is the approach we are proposing today.

This “prospective” approach would not formally apply the standard to all of the gasoline produced in the 2007 calendar year. As a result, it would not formally ensure that the total volume of renewable fuel required to be used in 2007 would actually be used. However, given the present circumstances, we believe this is an appropriate way to implement the Act's provisions. We are confident that the combined effect of the proposed regulatory requirements for 2007 and the expected market demand for renewable fuels will lead to greater renewable fuel use in 2007 than is called for under the Act. Furthermore, refiners and importers are not required to meet any requirements under the Act until EPA adopts the regulations, and EPA is authorized to consider appropriate lead time in establishing the regulatory requirements.

Under this option we believe there would be reasonable lead-time for regulated parties to meet their 2007 compliance obligations.

The statutory default standard for 2006 is the one exception to this, since it directly establishes a renewable fuel obligation applicable to refiners and importers in the event that EPA does promulgate regulations.

While we are proposing to apply the renewable fuel standard for 2007 prospectively only from the effective date of the final rule, we nevertheless request comment on all these options for addressing compliance in calendar year 2007.

4. Renewable Volume Obligations

In order for an obligated party to demonstrate compliance, the percentage standards described in Section III.A.2 which are applicable to all obligated parties must be converted into the volume of renewable fuel each obligated party is required to satisfy. This volume of renewable fuel is the volume for which the obligated party is responsible under the RFS program, and is referred to here as its Renewable Volume Obligation (RVO).

The calculation of the RVO requires that the standard shown in Table III.A.2-1 for a particular compliance year be multiplied by the gasoline volume produced by an obligated party in that year. To the degree that an obligated party did not demonstrate full compliance with its RVO for the previous year, the shortfall is included as a deficit carryover in the calculation. The equation used to calculate the RVO for a particular year is shown below:

RVO

= Std

x GV

+ D

−1

Where

RVO

= The Renewable Volume Obligation for the obligated party for year i, in gallons.

Std

= The RFS program standard for year i, in percent.

= The non-renewable gasoline volume produced by an obligated party in year i, in gallons.

= Renewable fuel deficit carryover from the previous year, in gallons.

The Energy Act only permits a deficit carryover from one year to the next if the obligated party achieves full compliance with its RVO including the deficit carryover in the second year. Thus deficit carryovers could not occur two years in succession. They could, however, occur as frequently as every other year for a given obligated party.

The calculation of an obligated party's RVO is necessarily retrospective, since the total gasoline volume that it produces in a calendar year will not be known until the year has ended. However, the obligated party will have an incentive to project gasoline volumes, and thus the RVO, throughout the year so that it can spread its efforts to comply across the entire year. Most refiners and importers will be able to project their annual gasoline production volumes with a minimum of uncertainty based on their historical operations, capacity, plans for facility downtimes, knowledge of gasoline markets, etc. Even if unforeseen circumstances (e.g., hurricane, unit failure, etc) significantly reduced the production volumes in comparison to their projections, their RVO would likewise be reduced proportionally and their ability to comply with the RFS requirements would be only minimally affected. Each obligated party's projected RVO for a given year becomes more accurate as that year progresses, but the obligated party should nevertheless have a sufficiently accurate estimate of its RVO at the beginning of the year to allow it to begin its efforts to comply.

B. What Counts as a Renewable Fuel in the RFS Program?

Section 211(o) of the Clean Air Act defines “renewable fuel” and specifies many of the details of the renewable fuel program. The following section provides EPA's views and interpretations on issues related to what fuels may be counted towards compliance with the RVO, and how they are counted.

1. What Is a Renewable Fuel That Can Be Used for Compliance?

The statutory definition of renewable fuel includes cellulosic ethanol and waste derived ethanol. It includes biodiesel, as defined in the Energy Act.

It also includes all motor vehicle fuels that are produced from biomass material such as grain, starch, oilseeds, animal, or fish materials including fats, greases and oils, sugarcane, sugar beets, tobacco, potatoes or other biomass. In addition, it includes motor vehicle fuels made using a feedstock of natural gas if produced from a biogas source such as a landfill, sewage waste treatment plant, feedlot, or other place where decaying organic material is found.

As discussed below, for purposes of this rulemaking, the regulations separate “biodiesel” as defined in the Energy Act, into biodiesel (diesels that meet the Energy Act's definition and are a mono aklyl ester) and renewable diesel (other diesels that meet the Energy Act's definition but are not mono akly esters.

According to the Act, the motor vehicle fuels must be used “to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.” Some motor vehicle fuels can be used in both motor vehicles or nonroad engines or equipment. For example, highway gasoline and diesel fuel are often used in both highway and off-highway applications. Compressed natural gas can likewise be used in either highway or nonroad applications. For purposes of the renewable fuel program, EPA intends to consider a fuel to be a “motor vehicle fuel” and to be a “fuel mixture used to operate a motor vehicle,” based on its potential for use in highway vehicles, without regard to whether it in fact is used in a highway or nonroad vehicle. If it is a fuel that could be used in highway vehicles, it will satisfy these parts of the definition of renewable fuel, whether it is later used in highway or nonroad applications. This will allow a motor vehicle fuel that otherwise meets the definition to be counted towards an RVO without the need to track it to determine its actual application in a highway vehicle. This is also consistent with the requirement that EPA base the renewable fuel obligation on estimates of the entire volume of gasoline consumed, without regard to whether it is used in highway or nonroad applications. Fuels that otherwise meet this definition but are designated by the producer for use in boilers, or heaters, or any use other than highway or nonroad use, would not meet the definition of renewable fuel.

Renewable fuel, as defined, may be made from a number of different types of feedstocks. For example, the Fisher-Tropsch process can use methane gas from landfills as a feedstock, to produce diesel or gasoline. Vegetable oil made from oilseeds such as rapeseed or soybeans can be used to make biodiesel or renewable diesel. Methane, made from landfill gas (biogas) can be used to make methanol. Also, some vegetable oils or animal fats can be processed in distillation columns in refineries to make gasoline; as such, the renewable feedstock serves as a “biocrude,” and the resulting gasoline or diesel product would be a renewable fuel. This last example is discussed in further detail in Section III.B.3 below.

As this discussion shows, the definition of renewable fuel in the Act is broad in scope, and covers a wide range of fuels. While ethanol is used primarily in combination with gasoline, other fuels that meet the definition of renewable fuel include biodiesel and various alternative fuels that can be used in their neat form, such as ethanol, methanol or natural gas, without blending into gasoline and without being used to produce a gasoline blending component (such as ETBE). The definition of renewable fuel in the Act is not limited to fuels that can be blended with gasoline. At the same time, the RFS regulatory program is to “ensure that gasoline sold or introduced into commerce * * * contains the applicable volume of renewable fuel.” This applicable volume is specified as a total volume of renewable fuel, in the billions of gallons on an aggregate basis. Congress also clearly specified that one renewable fuel, biodiesel, could be counted towards compliance even though it is not a gasoline component, and does not directly displace or replace gasoline. The Act is unclear on whether other fuels that meet the definition of renewable fuel, but are not used in gasoline, could also be used to demonstrate compliance towards the aggregate national use of renewable fuels.

EPA interprets the Act as allowing regulated parties to demonstrate compliance based on any fuel that meets the statutory definition for renewable fuel, whether it is directly blended with gasoline or not. This would include neat alternative fuels such as ethanol, methanol, and natural gas that meet the definition of renewable fuel. This is appropriate for several reasons. First, it promotes the use of all renewable fuels, which will further the achievement of the purposes behind this provision. Congress did not intend to limit the program to only gasoline components, as evidenced by the provision for bio-diesel, and the broad definition of renewable fuel evidences an intention to address more renewable fuels than those used with gasoline. Second, in practice EPA expects that the overwhelming volume of renewable fuel used to demonstrate compliance with the

renewable fuel obligation would still be ethanol blended with gasoline. Whether one counts or does not count these additional renewable fuels would not in practice change whether the total national goal for renewable fuel use was met, given the size of the goal specified in the Act and the form in which the total is expressed. Finally, as discussed later, EPA's compliance program is based on assigning volumes at the point of production, and not at the point of blending into motor vehicle fuel. This interpretation would avoid the need to track renewable fuels downstream to ensure they are blended with gasoline and not used in their neat form; the gasoline that is used in motor vehicles is reduced by the presence of renewable fuels in the gasoline pool whether they are blended with gasoline or not EPA believes its proposal is consistent with the intent of Congress and is a reasonable interpretation of the Act.

We are therefore proposing that in addition to any renewable fuels that are actually blended into gasoline and are designated for use in a highway vehicle, we would also count any renewable fuels falling into the following categories as being valid for RFS compliance purposes:

1. Any renewable fuels used in nonroad applications;

2. Any renewable fuels used in their neat (unblended) form in onroad and nonroad applications; and

3. Any renewable fuel used in a motor vehicle that does not normally run on gasoline. For instance, biogas used in a CNG vehicle, or biogenic methanol used in a dedicated methanol vehicle.

The Agency solicits comment on this approach.

Under the Act, renewable fuel includes “cellulosic biomass ethanol” and “waste derived ethanol”, each of which is defined separately. Ethanol can be cellulosic biomass ethanol in one of two ways, as described below.

Ethanol Made From a Cellulosic Feedstock.

The simplest process of producing ethanol is by fermenting sugar in sugar cane, but can also be produced from carbohydrates in corn and other feedstocks. This process is accomplished by first converting the carbohydrates to sugar. Ethanol can also be produced from complex carbohydrates, such as the cellulosic portion of plants or plant products. The cellulose is first converted to sugars (by hydrolysis); then the same fermentation process is used as for carbohydrates to make ethanol. Cellulosic feedstocks (composed of cellulose and hemicellulose) are currently more difficult and costly to convert to sugar than are carbohydrates because of this intermediate conversion step. While the cost and difficulty are a disadvantage, the cellulosic process offers the advantage that more feedstocks can be used and more volume of ethanol can be produced.

The Act provides the definition of cellulosic biomass ethanol, which states:

“The term ‘cellulosic biomass ethanol’ means ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis, including:

(i) Dedicated energy crops and trees;

(ii) Wood and wood residues;

(iii) Plants;

(iv) Grasses;

(v) Agricultural residues;

(vi) Animal wastes and other waste materials, and

(viii) Municipal solid waste”

Examples of cellulosic biomass source material include rice straw, switch grass, and wood chips. Ethanol made from these materials would qualify under the definition as cellulosic ethanol. In addition to the above sources of feedstocks for cellulosic biomass ethanol, the Act's definition also includes animal waste, municipal solid wastes, and other waste materials While these materials may or may not contain cellulosic material, their inclusion in the definition requires that ethanol made from such sources be treated as cellulosic biomass ethanol under the regulations. “Other waste materials” generally includes waste material such as sewage sludge, waste candy, and waste starches from food production, but for purposes of the definition of cellulosic ethanol discussed in III.B.1.b below, it can also mean waste heat obtained from an off-site combustion process.

Although the definitions of “cellulosic biomass ethanol” and “waste derived ethanol” both include animal wastes and municipal solid waste in their respective lists of covered feedstocks, there remains a distinction between these types of ethanol. If the animal wastes or municipal solid wastes contain cellulose or hemicellulose, the resulting ethanol can be termed “cellulosic biomass ethanol.” If the animal wastes or municipal solid wastes do not contain cellulose or hemicellulose, then the resulting ethanol is labeled “waste derived ethanol.”

Ethanol Made From Any Feedstock in Facilities Run Mostly With Biomass-Based Fuel.

The definition of cellulosic biomass ethanol in the Act also provides that ethanol made at any facility—regardless of whether cellulosic feedstock is used or not—may be defined as cellulosic if at such facility “animal wastes or other waste materials are digested or otherwise used to displace 90 percent or more of the fossil fuel normally used in the production of ethanol.” The statutory language suggests that there are two methods through which “animal and other waste materials” may be considered for displacing fossil fuel. The first method is the digestion of animal wastes or other waste materials. EPA proposes to interpret the term “digestion” to mean the conversion of animal or other wastes into methane, which can then be combusted as fuel. We base our interpretation on the practice in industry of using anaerobic digesters to break down waste products such as manure into methane. Anaerobic digestion refers to the breakdown of organic matter by bacteria in the absence of oxygen, and is used to treat waste to produce renewable fuels. We note also that the digestion of animal wastes or other waste materials to produce the fuel used at the ethanol plant does not have to occur at the plant itself. Methane made from animal or other wastes offsite and then purchased and used at the ethanol plant would also qualify.

The second method is suggested by the term “otherwise used” which we propose to interpret as meaning (1) the direct combustion of the waste materials as fuel at an ethanol plant, or (2) the use of thermal energy that itself is a waste product; e.g., waste heat that is obtained from an off-site combustion process such as a neighboring plant that has a furnace or boiler from which the waste heat is captured. With respect to the first meaning, waste materials from tree farms (tops, branches, limbs, etc), or waste materials from saw mills (sawdust, shavings and bark) as well as other vegetative waste materials such as corn stover, or sugar cane bagasse, could be used as fuel for gasifier/boiler units at ethanol plants, since they are waste materials and would not be used as a feedstock to carbohydrate-based ethanol plants. Although such waste materials conceivably could be feedstocks to a cellulosic ethanol plant, its use as a fuel at a carbohydrate based ethanol plant does not subvert the intent of the definition.

On the other hand, wood from plants or trees that are grown as an energy crop may not qualify as a waste-derived fuel in an ethanol facility because such wood would not qualify as waste materials under this portion of the definition. Under the definition of renewable fuels and cellulosic biomass ethanol, however, such wood material could serve as a feedstock in a cellulosic ethanol plant, since these definitions do not restrict such feedstock to waste materials only.

Today's regulations will require owners of ethanol plants to keep records of fuel use to ensure compliance with and enforcement of this provision of the definition of cellulosic ethanol. Due to potential enforcement-related problems associated with application of this component of the definition of cellulosic ethanol to foreign facilities, we intend for the final rule to develop compliance and enforcement related safeguards similar to those set forth in proposed 80.1165(f), (g), (h) and (j), and with additional inspection, audit, recordkeeping and reporting safeguards to verify compliance with the requirements on fuel use at foreign facilities. We seek comment on the most effective means of doing this. Because of the difficulty of implementing these safeguards, however, we also solicit comment on a provision that would limit the application of this definition of cellulosic ethanol only to ethanol plants in the U.S.

Regarding the use of waste heat as a source of thermal energy, we note that there may be situations in which an off-site furnace, boiler or heater creates excess or waste heat that is not used in the process for which the thermal energy is employed. For example, a glass furnace generates a significant amount of waste heat that often goes unused. We are proposing to include waste heat in the definition of “other waste materials”, and also that waste heat captured and used as a source of thermal energy in an ethanol plant would satisfy the requirement of other waste materials being “otherwise used” to make ethanol. Although the source of the waste heat is ultimately a fossil fuel in most cases, we recognize that without the capture of the heat and subsequent use in the ethanol plant, that energy would be unused, and the ethanol plant would consume the equivalent amount of fossil fuel. Thus, for the same amount of fossil fuel consumption at the off-site plant, heat energy capture would result in displacement of fossil fuel use at the ethanol plant. Because of potential confusion identifying thermal energy that is waste heat from fossil fuel combustion sources on site (i.e., at the ethanol plant itself), we are limiting this proposal to waste heat captured at off-site plants. The Agency solicits comment on our proposal to consider waste heat in the definition of “other waste materials”.

We propose to interpret the term “fossil fuel normally used in the production of ethanol” to mean fossil fuel used at the facility in the ethanol production process itself, rather than other phases such as trucks transporting product, and fossil fuel used to grow and harvest the feedstock. Therefore the diesel fuel that trucks consume in hauling wood waste from sawmills to the ethanol facility would not be counted in determining whether the 90% displacement criteria has been met. We are interpreting it in this way because we believe the accounting of fuel use associated with transportation and other life cycle activities would be extremely difficult and in many cases impossible.

The Agency solicits comments on this aspect of our approach in accounting for fossil fuel displacement.

In Section IX of today's preamble we discuss our analysis of the lifecycle fuel impacts of the RFS rule, with respect to greenhouse gas (GHG) emissions. While we do account for fuel used in hauling materials to ethanol plant in our analysis, we are using average nationwide values, rather than data collected for individual plants.

Based on the operation of ethanol plants, we are viewing this definition to apply to waste materials used to produce thermal energy rather than electrical energy. Electrical usage at ethanol plants is used for lights and equipment not related to the production of ethanol. Also, the calculation of fossil fuel used to generate such electrical usage would be difficult because it is not always possible to track the source of electricity that is purchased off-site. We are therefore proposing that the displacement of 90 percent of fossil fuels at the ethanol plant means those fuels consumed on-site and that are used to generate thermal energy used to produce ethanol. The term “fossil fuel normally used in the production of ethanol” in today's proposal means fossil fuel that is combusted at the facility itself to produce thermal energy. Owners are required to keep records of fuel (waste-derived and fossil fuel) used for thermal energy for verification of their claims. They will also be required to track the fossil fuel equivalent of the waste heat captured and used in the ethanol process. Since such waste heat would typically be purchased through agreement with the off-site owner, we do not feel it burdensome for owners to track such information. Owners would therefore calculate the amount of energy in Btu's associated with waste-derived fuels (including the fossil fuel equivalent waste heat), and divided by the total energy in Btus used to produce ethanol in a given year. Holders of RINs associated with the sale or trade of such cellulosic ethanol would get the benefit of the 2.5 credit (through 2012 when such credit is valid).

In the event that the requirements of 90 percent displacement of fossil fuel are not met, the owner of a facility producing such ethanol would be required to obtain additional RINs to make up whatever deficit exists for those RINs sold or traded with a value of 2.5. Assuming this is made up, then holders of the RINs associated with the ethanol the plant produced in the previous year would not be affected. We solicit comment on this proposed approach.

Ethanol that is made from the non-cellulosic portions of animal, other waste, and municipal waste.

“Waste derived ethanol” is defined in the Act as ethanol derived from “animal wastes, including poultry fats and poultry wastes, and other waste materials; * * * or municipal solid waste.” Both animal wastes and municipal solid waste are also listed as allowable feedstocks for the production of “cellulosic biomass ethanol.” The determination of the appropriate category of ethanol is based on whether the feedstocks on question contain cellulose or hemicellulose that is used to make the ethanol. Thus, if the ethanol is made from the non-cellulosic portions of animal, other waste, or municipal waste, it is labeled “waste derived ethanol.”

2. What Is Biodiesel?

The definition of renewable fuel in the Act includes corn-based and cellulosic biomass ethanol, waste derived ethanol, and the renewable fuel portion of blending components derived from renewable fuel. Biodiesel is also specifically named as being included in the Act's definition of renewable fuel. The Act states that “The term ‘renewable fuel’ includes * * * biodiesel (as defined in section 312(f) of the Energy Policy Act of 1992.” This definition, as modified by Section 1515 of the Energy Act states:

The term “biodiesel” means a diesel fuel substitute produced from nonpetroleum renewable resources that meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title, and includes biodiesel derived from animal wastes, including poultry fats and poultry wastes, and other waste materials, or municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater.

This definition of biodiesel would include both mono-alkyl esters which meet ASTM specification D-6751

(the most common meaning of the term

“biodiesel”) that have been registered with EPA, and any non-esters that are intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, have been registered with the EPA, and are made from any of the feedstocks listed above.

In the event that the ASTM specification D-6751 is succeeded with a different number in the future, EPA may revise the regulations accordingly at such time.

To implement the above definition of biodiesel in the context of the RFS rulemaking while still recognizing the unique history and role of mono-alkyl esters meeting ASTM D-6751, we propose to divide the Act's definition of biodiesel into two separate parts: biodiesel (mono-alkyl esters) and non-ester renewable diesel. The combination of “biodiesel (mono-alkyl esters)” and “non-ester renewable diesel” in the regulations would fulfill the Act's definition of biodiesel. The Agency solicits comment on this approach and specifically asks whether the “non-ester renewable diesel” definition be referenced explicitly to ASTM D-975.

Biodiesel (Mono-Alkyl Esters).

Under this part, the term “biodiesel (mono-alkyl esters)” means a motor vehicle fuel which: (1) Meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title (Clean Air Act Section 211); (2) is a mono-alkyl ester; (3) meets ASTM specification D-6751-02a; (4) is intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, and (5) is derived from nonpetroleum renewable resources including, but not limited to, animal wastes, including poultry fats and poultry wastes, and other waste materials, or municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater.

Non-Ester Renewable Diesel.

The term “non-ester renewable diesel” means a motor vehicle fuel which: (1) Meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title (Clean Air Act Section 211); (2) is not a mono-alkyl ester; (3) is intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, and (4) is derived from nonpetroleum renewable resources including, but not limited to, animal wastes, including poultry fats and poultry wastes, and other waste materials, or municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater. Current examples of a non-ester renewable diesel include: “renewable diesel” produced by the Neste process, or diesel fuel produced by processing fats and oils through a refinery hydrotreating process.

3. Is Motor Fuel That Is Made From a Renewable Feedstock a Renewable Fuel?

We interpret the statutory definition of renewable fuels to include all gasoline or diesel that is made from a class of feedstocks called “biocrudes”, which are defined as biologically derived feedstocks (such as fats and greases). We are providing a definition of “biocrude-based renewable fuels” to mean gasoline or diesel products resulting from the processing of biocrudes in production units within refineries that process crude oil and other petroleum based feedstocks and which make gasoline and diesel fuel.

A particular batch of biocrude used as feedstock to a production unit would replace crude oil or other petroleum based feedstocks which ordinarily would be the feedstock in that process unit. The non-ester renewable diesel defined in Section III.B.2.b above could be one such type.

Biocrude-based renewable fuels will need to be registered under the provisions contained in 40 CFR 79 Part 4 before they can be sold commercially.

We are assuming that all of the biocrude used as a feedstock in a refinery unit will end up as a biocrude-based renewable fuel. Rather than requiring the refiner to document what portion of the biocrude-based renewable fuel is other than diesel or gasoline (e.g., jet fuel), we are proposing to have the volume of the biocrude itself count as the volume of renewable fuel produced for the purposes of determining the volume block codes that are in the RIN (discussed in further detail in Section III.D). While this approach may result in some products such as jet fuel being counted as renewable fuel, we believe the majority of the products produced will be motor vehicle fuel because we assume refiners who elect to use biocrudes would do so to help meet the requirements of this rule. Furthermore, both diesel and gasoline presently make up about 85 percent of the product slate of refineries on average. This amount that has been steadily increasing for over time, and we expect that the percentage will continue to increase as demand for gasoline and diesel increases.

We are also proposing that the Equivalence Value assigned to biocrude-based renewable fuels be designated as 1.0, despite the fact that they might warrant a higher value based on their energy content as described in the next section.

This approach should balance out the likelihood that some of the biocrude-based renewable fuel is not a motor vehicle fuel.

With respect to biodiesel, however, since such fuel is typically not made in a traditional petroleum-based refinery, it would not be a biocrude-based renewable fuel and would thus not be limited to the 1.0 Equivalence Value.

4. What Are “Equivalence Values” for Renewable Fuel?

One question that EPA must address is how to count volumes of renewable fuel in determining compliance with the renewable volume obligation. For instance, the Act stipulates that every gallon of cellulosic ethanol should count as if it were 2.5 gallons for RFS compliance purposes. The Act does not stipulate similar values for other renewable fuels, but as described below we believe it is appropriate to do so.

We are proposing that the “Equivalence Values” for different renewable fuels be based on their energy content in comparison to the energy content of ethanol, and adjusted as necessary for their renewable content. The result is an Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, and for cellulosic ethanol of 2.5. However, the methodology can be used to determine the appropriate equivalence value for any other potential renewable fuel as well.

This section describes why we believe that the use of relative energy content is appropriate under the Act, and our investigation of the alternative use of lifecycle analyses as the basis of Equivalence Values.

Authority Under The Act To Establish Equivalence Values.

We are proposing that Equivalence Values be assigned to every renewable fuel to provide an indication of the number of gallons that can be claimed for compliance purposes for every physical gallon of renewable fuel. An Equivalence Value of 1.0 would mean that every physical gallon of renewable fuel would count as one gallon for RFS compliance purposes. An Equivalence Value greater than 1.0 would mean that every physical gallon of renewable fuel would count as more than one gallon for RFS compliance purposes, while a value less than 1.0 would count as less than one gallon.

We are interpreting the Act as allowing EPA to develop Equivalence Values according to the methodology discussed below. We believe that the use of Equivalence Values is consistent with the intent of Congress to treat different renewable fuels differently in different circumstances, and to provide

incentives for use of renewable fuels in certain circumstances, as evidenced by those specific circumstances addressed by Congress. The Act has several provisions that provide for mechanisms other than straight volume measurement to determine the value of a renewable fuel in terms of RFS compliance. For example, 1 gallon of cellulosic biomass or waste derived ethanol is to be treated as 2.5 gallons of renewable fuel. EPA is also required to establish an “appropriate amount of credits” for biodiesel, and to provide for “an appropriate amount of credit” for using more renewable fuels than are required to meet your obligation. EPA is also to determine the “renewable fuel portion” of a blending component derived from a renewable fuel. All of these statutory provisions provide evidence that Congress did not limit this program solely to a straight volume measurement of gallons in the context of the RFS program for certain specified circumstances.

The Act is unclear as to whether a straight gallon measurement is required in circumstances other than those specified by Congress. We believe the Act can and should be interpreted to allow the use of Equivalence Values in those circumstances. First, this is consistent with the way Congress treated the various specific circumstances noted above, and thus is basically a continuation of that process. Second, EPA does not believe that providing such an Equivalence Value for this small volume of renewable fuel will interfere in any way with meeting the total national volume goals for usage of renewable fuel. We are proposing to use an Equivalence Value of 1.0 for ethanol other than cellulosic biomass or waste derived ethanol, and we expect that there will only be very limited additional situations where an Equivalence Value other than 1.0 is used. As a result, this approach is a reasonable way for the RFS program to ensure that the total volume of renewable fuels will be used as required under the Act.

Energy Content and Renewable Content as the Basis for Equivalence Values.

We believe it is appropriate to base the Equivalence Value assigned to a particular renewable fuel on the degree to which the renewable fuel supplants the petroleum content of fuel used in a motor vehicle. This is consistent with the Act's definition of renewable fuel, which refers to the degree to which it is directly used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle. The degree to which the fossil fuel is replaced is best represented by its relative energy content. To appropriately account for the different energy contents of different renewable fuels as well as the fact that some renewable fuels actually contain some non-renewable content, we propose to calculate Equivalence Values using both the renewable content of a renewable fuel and its energy content. This section describes our proposal for calculating the Equivalence Values.

In order to take the energy content of a renewable fuel into account when calculating the Equivalence Values, we must identify an appropriate point of reference. Ethanol would be a reasonable point of reference as it is currently the most prominent renewable fuel in the transportation sector, and it is likely that the authors of the Act saw ethanol as the primary means through which the required volumes would be met in at least the first years of the RFS program. By comparing every renewable fuel to ethanol on an equivalent energy content basis, each renewable fuel could be assigned an Equivalence Value that precisely accounts for the amount of petroleum in motor vehicle fuel that is reduced or replaced by that renewable fuel in comparison to ethanol. To the degree that corn-based ethanol continues to dominate the pool of renewable fuel, this approach would allow actual volumes of renewable fuel to be consistent with the volumes required by the Act while still allowing some renewable fuels to be attributed a higher value in terms of RFS compliance to the extent that they have a higher energy content than ethanol.

Equivalence Values should also account for the renewable content of renewable fuels, since the presence of any non-renewable content impairs the ability of the renewable fuel to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle. The Act specifically states that only the renewable fuel portion of a blending component should be considered part of the applicable volume under the RFS program. We have interpreted this to mean that every renewable fuel should be evaluated at the molecular level to distinguish between those components that were derived from a renewable feedstock, versus those components that were derived from a fossil fuel feedstock. Along with energy content in comparison to ethanol, the relative amount of renewable versus non-renewable content can then be used directly as the basis for the Equivalence Value.

We propose that the calculation of Equivalence Values should simultaneously take into account both the renewable content of a renewable fuel and its energy content in comparison to ethanol. To accomplish this, we propose the following formula:

EV = (R

/ R

Eth

) × (EC

/ EC

Eth

)

Where:

EV = Equivalence Value for the renewable fuel.

= Renewable content of the renewable fuel, in percent.

Eth

= Renewable content of ethanol, in percent.

= Energy content of the renewable fuel, in Btu per gallon (LHV).

Eth

= Energy content of ethanol, in Btu per gallon (LHV).

R is a measure of that portion of a single renewable fuel molecule which can be considered to have come from a renewable source. Since R is being combined with relative energy content in the formula above, the value of R cannot be based on the weight fraction of the renewable atoms in the molecule, but rather must be based on the energy content of those atoms. As a result the calculation of R for any particular renewable fuel requires an analysis of the chemical process through which it was produced. A detailed explanation of calculations for R and several examples are given in a technical memorandum in the docket

“Calculation of equivalence values for renewable fuels under the RFS program”, memo from David Korotney to EPA Air Docket OAR-2005-0161.

In the case of ethanol, denaturants are added to preclude its use as food. Denaturants are generally a fossil-fuel based, gasoline-like hydrocarbon in concentrations of 2-5 volume percent, with 5 percent being the most common historical level. In general this would mean that the Equivalence Value of ethanol would be 0.95. However, we believe that the Equivalence Value for ethanol should be specified as 1.0 despite the presence of a denaturant. First, as stated above, ethanol is expected to dominate the renewable fuel pool for at least the next several years, and it is likely that the authors of the Act recognized this fact. Thus it seems likely that it was the intent of the authors of the Act that each physical gallon of denatured ethanol be counted as one gallon for RFS compliance purposes. Second, the accounting of ethanol has historically ignored the presence of the denaturant. For instance, under Internal Revenue Service (IRS) regulations the denaturant can be counted as ethanol by parties filing claims to the IRS for the Federal excise tax credit. Also, EIA reporting requirements for ethanol producers

allow them to include the denaturant in their reported volumes.

Since we are proposing that denatured ethanol be assigned an Equivalence Value of 1.0, this must be reflected in the values of R

Eth

and EC

Eth

. We have calculated these values to be 93.1 percent and 77,550 Btu/gal, respectively. Details of these calculations can be found in the aforementioned technical memorandum to the docket.

The calculation of the Equivalence Value for a particular renewable fuel can lead to values that deviate only slightly from 1.0, and/or can have varying degrees of precision depending on the uncertainty in the value of R or EC

. We are therefore proposing three simplifications to streamline the application of Equivalence Values in the context of the RFS program. First, consistent with our approach to the R value for ethanol, we are proposing that all Equivalence Values calculated to be in the range of 0.9-1.2 be treated as if they were exactly 1.0. This approach would eliminate many of the complexities described in Section III.D.2 that are associated with using renewable fuels for RFS compliance purposes that have an Equivalence Value other than 1.0. Second, we propose that several bins be created for renewable fuels with Equivalence Values above 1.0. These bins would replace the calculated Equivalence Values with standardized ones to account for uncertainty in the calculations as well as to simplify their application. We propose that the bins be 1.0, 1.3, 1.5, and 1.7. Each renewable fuel would be assigned to the bin that is closest to its calculated Equivalence Value. Finally, we propose that all Equivalence Values, if any, which are calculated to be less than 0.9 be rounded to the first decimal place.

Using the methodology described above, we calculated the Equivalence Values for a number of different renewable fuels expected to be in use over the next few years, and modified them according to our proposed rounding protocols. These are shown in the table below.

Table III.B.4-1.—Proposed Equivalence Values for Some Renewable Fuels

Equivalence Value (EV)

Cellulosic biomass ethanol or waste-derived ethanol

2.5

Ethanol from corn, starches, or sugar

1.0

Biodiesel (mono alkyl ester)

1.5

Non-ester renewable diesel

1.7

Butanol

1.3

ETBE from corn ethanol

0.4

Since there are a wide variety of possible renewable fuels that could qualify under the RFS program, there may be cases in which a party produces a renewable fuel not shown in Table III.B.4-1. In such cases we propose to allow the producer to submit a petition to the Agency describing the renewable fuel, its feedstock and production process, and the calculation of its Equivalence Value. The Agency would review the petition and assign an appropriate Equivalence Value to the renewable fuel based on the proposed rounding protocols described above. Regarding publication of the newly assigned Equivalence Value, we could publish it in the

Federal Register

at the same time as the annual standard is published each November. We request comment on whether publishing new Equivalence Values in this manner is appropriate.

Regarding biodiesel (mono alkyl esters), we also considered an additional approach in setting the Equivalence Value. Since ethanol derived from waste products such as animal wastes and municipal solid waste will be assigned an Equivalence Value of 2.5 based on a requirement in the Act, it might be appropriate to create a parallel provision for biodiesel made from wastes. Under this approach, biodiesel made from waste products would be assigned an Equivalence Value of 2.5 through 2012. Currently, waste products (for example, poultry fats and poultry wastes, municipal solid waste, or wastewater sludge) make up less than 10 percent of biodiesel feedstocks. This approach would have the effect of incentivizing the use of waste products and recycled biomass to make biodiesel. Beyond the RFS program, it could also set a precedent to promote recycling and waste conservation. While we are not proposing to set the Equivalence Value for waste-derived biodiesel at 2.5 in today's action, we nevertheless believe that this approach has merit and request comment on it.

Lifecycle Analyses as The Basis for Equivalence Values.

Although we are proposing that Equivalence Values be based on energy content relative to ethanol and renewable content, some stakeholders have suggested that Equivalence Values should be based on lifecycle analyses. Such an approach may have merit, but it would also raise a number of challenges. Consequently, we are inviting comment here not only on the merit and basis for setting equivalence values on a lifecycle basis, but also the appropriate means of doing so.

Lifecycle analyses involve an examination of fossil fuel used, and emissions generated, at all stages of a renewable fuel's life. A typical lifecycle analysis examines production of the feedstock, its transport to a conversion facility, the conversion of the feedstock into renewable motor vehicle fuel, and the transport of the renewable fuel to the consumer. At each stage, every activity that consumes fossil fuels or results in emissions is quantified, and these energy consumption and emission estimates are then summed over all stages. By accounting for every activity associated with renewable fuels over their entire life, we can assess renewable fuels in terms of not just their impact within the transportation sector, but across all sectors, and thus for the nation as a whole. In this way they provide a more complete picture of the potential impacts of different fuels or different fuel sources.

Advocates for using lifecycle analyses for setting the Equivalence Values for different renewable fuels indicate that there could be several advantages to this approach. First, doing so could create an incentive for obligated parties to choose renewable fuels having a greater ability to reduce fossil fuel use or resulting emissions, since such renewable fuels would have higher Equivalence Values and thus greater value in terms of compliance with the RFS requirements. The preferential demand for renewable fuels having higher Equivalence Values could in turn spur additional growth in production of these renewable fuels. Second, using lifecycle analyses as the basis for Equivalence Values could orient the RFS program more explicitly towards reducing fossil fuel use or emissions.

At the same time, the use of lifecycle analyses to establish the Equivalence Values for different renewable fuels also raises a number of issues. For instance, lifecycle analyses can be conducted using several different metrics, including total fossil fuel consumed, petroleum energy consumed, criteria pollutant emissions (e.g., VOC, NO

, PM) carbon dioxide emissions, or greenhouse gas emissions. Each metric would result in a different Equivalence Value for the same renewable fuel. At the present time there is no consensus on which metric would be most appropriate for this purpose.

There is also no consensus on the approach to lifecycle analyses themselves. Although we have chosen to base our lifecycle analyses on Argonne National Laboratory's GREET model for the reasons described in Section IX, there are a variety of other lifecycle models and analyses available. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers. Lifecycle analyses must also contend with the fact that the inputs and assumptions generally represent industry-wide averages even though energy consumed and emissions generated can vary widely from one facility or process to another. There currently exists no single body, governmental or otherwise, that has organized a comprehensive dialogue among stakeholders about the appropriate tools and assumptions behind any lifecycle analyses with the goal of coming to agreement.

Another issue to using lifecycle analyses as the basis for Equivalence Values pertains to the ultimate impact that the RFS program would have on petroleum use, fossil fuel use, criteria pollutant emissions, and/or emissions of GHGs. With a fixed volume of renewable fuel required under the RFS program, any renewable fuel with an Equivalence Value greater than 1.0 would necessarily mean that fewer actual gallons would be needed to meet the RFS standard. Thus, the advantage per gallon may be offset with fewer overall gallons, resulting in no overall additional benefit unless the RFS standard was simultaneously adjusted.

Finally, lifecycle analyses of different renewable fuels are likely to change over time as farming practices and process technologies evolve. Significant changes would necessitate corresponding changes in the RFS program to adjust the Equivalence Values on an ongoing basis which would add uncertainty into the long-term RIN market.

We request comment on all issues associated with the use of lifecycle analyses in establishing the Equivalence Values for different renewable fuels for the RFS program.

C. What Gasoline Is Used To Calculate the Renewable Fuel Obligation and Who Is Required To Meet the Obligation?

1. What Gasoline Is Used to Calculate the Volume of Renewable Fuel Required To Meet a Party's Obligation?

The Act requires EPA to promulgate regulations designed to ensure that “gasoline sold or introduced into commerce in the United States (except in noncontiguous states or territories)” contains on an annual average basis, the applicable aggregate volumes of renewable fuels as prescribed in the Act.

To implement this provision, we are proposing that the volume of gasoline used to determined the renewable fuel obligation include all finished gasoline, RFG and conventional, produced or imported for use in the contiguous United States during the annual averaging period. We are also proposing to include in the volume of gasoline used to determine the renewable fuel obligation all unfinished gasoline that becomes finished gasoline upon the addition of oxygenate blended downstream from the refinery or importer. This would include both unfinished reformulated gasoline, called “reformulated gasoline blendstock for oxygenate blending,” or “RBOB,” and unfinished conventional gasoline (e.g. sub-octane conventional gasoline), called “CBOB.”

CAA Section 211(o)(2)(A)(i), as added by Section 1501(a) of the Energy Policy Act of 2005.

Under the proposed rule, the volume of any other unfinished gasoline or blendstock, such as butane, would not be included in the volume used to determine the renewable fuel obligation, except where the blendstock is combined with other blendstock or finished gasoline to produce finished gasoline. Where a blendstock is blended with other blendstock to produce finished gasoline, RBOB, or CBOB, the total volume of the gasoline blend would be included in the volume used to determine the renewable fuels obligation for the blender. Where a blendstock is added to finished gasoline, only the volume of the blendstock would be included, since the finished gasoline would have been included in the compliance determinations of the refiner or importer of the gasoline.

Gasoline produced or imported for use in a noncontiguous state or U.S. territory

would not be included in the volume used to determine the renewable fuels obligation (unless the noncontiguous state or territory has opted-in to the RFS program), nor would gasoline, RBOB or CBOB exported for use outside the United States.

“Gasoline treated as blendstock,” or “GTAB,” would be treated as any other blendstock with regard to the RFS rule; i.e., where the GTAB is blended with other blendstock to produce gasoline, the total volume of the gasoline blend, including the GTAB, would be included in the volume gasoline used to determine the renewable fuel obligation for the blender. Where the GTAB is blended with finished gasoline, only the GTAB volume would be included.

The noncontiguous states are Alaska and Hawaii. The territories are the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Marianas.

For purposes of this preamble, the various gasoline products (as described above) that we are proposing to include in the volume of gasoline used to determine the renewable fuel obligation are collectively called “gasoline.”

Generally, ethanol and other renewable fuels would typically be used in gasoline, increasing the volume of the entire gasoline blend. We are proposing to exclude the volume of renewable fuels contained in gasoline from the volume of gasoline used to determine the renewable fuels obligation. In implementing the Act's renewable fuels requirement, our primary goal is to design a program that is simple, flexible and enforceable. If the program were to include renewable fuels in the volume of gasoline used to determine the renewable fuel obligation, then every blender that blends ethanol downstream from the refinery or importer would be subject to the renewable fuel obligation for the volume of ethanol that they blend. There are currently approximately 1,200 such ethanol blenders. Of these blenders, only those who blend ethanol into RBOB are regulated parties under current fuels regulations. Designating all of these ethanol blenders as obligated parties under the RFS program would greatly expand the number of regulated parties and increase the complexity of the RFS program beyond that which is necessary to carry out the renewable fuels mandate under the Act.

The Act provides that the renewable fuel obligation shall be “applicable to refiners, blenders, and importers, as appropriate.”

For the reasons discussed above, we believe it is appropriate to exclude downstream renewable fuel blenders from the group of parties subject to the renewable fuel obligation, and to exclude renewable fuels from the volume of gasoline used to determine the renewable fuel obligation. This exclusion would apply to any renewable fuels that are blended into gasoline at a refinery, contained in imported gasoline, or added at a downstream blending facility. Thus, for example, any ethanol added to RBOB or CBOB downstream from the refinery or importer would be excluded from the volume of gasoline used to determine the obligation. Any non-renewable fuel added downstream, however, would be included in the volume of gasoline used to determine the obligation. This approach has no impact on the total

volume of renewable fuels required, merely on the number of obligated parties. We invite comment on the proposal to exclude renewable fuels in the volume of gasoline subject to the renewable fuels obligation. As discussed earlier, in a similar manner this volume of renewable fuel would also be excluded from the calculation performed each year by EPA to determine the applicable percentage.

CAA Section 211(o)(3)(B), as added by Section 1501(a) of the Energy Policy Act of 2005.

2. Who Is Required To Meet the Renewable Fuels Obligation?

Under the proposed rule, persons who meet the definition of refiner, which includes blenders who produce gasoline by combining blendstocks or blending blendstocks into finished gasoline, and persons who meet the definition of importer under the fuels regulations would be subject to the renewable fuel obligation. As noted above, blenders who only blend renewable fuels downstream from the refinery or importer would not be subject to the renewable fuel obligation. Any person that is required to meet the renewable fuels obligation is called an “obligated party.” We generally refer to all of the obligated parties as refiners and importers, as the covered blenders are all refiners under the regulations.

A refiner or importer located in a noncontiguous state or U.S. territory would not be subject to the renewable fuel obligation and thus would not be an obligated party (unless the noncontiguous state or territory opts-in to the RFS program). A party located within the contiguous 48 states that “imports” into the 48 states gasoline produced or imported by a refiner or importer located in a noncontiguous state or territory would be an obligated party and must meet the renewable fuel obligation for such gasoline.

3. What Exemptions Are Available Under The RFS Program?

Small Refinery and Small Refiner Exemption.

The Act provides an exemption from the RFS standard for small refineries during the first five years of the program. The Act defines small refinery as “a refinery for which the average aggregate daily crude oil throughput for a calendar year (as determined by dividing the aggregate throughput for the calendar year by the number of days in the calendar year) does not exceed 75,000 barrels.”

Under the proposed rule, any gasoline produced at a refinery that qualifies as a small refinery under this definition is not counted in determining the renewable fuel obligation of a refiner until January 1, 2011. Where a refiner complies with the renewable fuel obligation on an aggregate basis for multiple refineries, the refiner may exclude from its compliance calculations gasoline produced at any refinery that qualifies as a small refinery under the RFS program. Beginning in 2011, small refineries would be required

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