24904 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2005–0161; FRL–8903–1] 

RIN 2060–A081 

Regulation of Fuels and Fuel 

Additives: Changes to Renewable Fuel 

Standard Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice of proposed rulemaking. 

SUMMARY: Under the Clean Air Act, as 

amended by Sections 201, 202, and 210 

of the Energy Independence and 

Security Act of 2007, the Environmental 

Protection Agency is required to 

promulgate regulations implementing 

changes to the Renewable Fuel Standard 

program. The revised statutory 

requirements specify the volumes of 

cellulosic biofuel, biomass-based diesel, 

advanced biofuel, and total renewable 

fuel that must be used in transportation 

fuel each year, with the volumes 

increasing over time. The revised 

statutory requirements also include new 

definitions and criteria for both 

renewable fuels and the feedstocks used 

to produce them, including new 

greenhouse gas emission thresholds for 

renewable fuels. For the first time in a 

regulatory program, an assessment of 

greenhouse gas emission performance is 

being utilized to establish those fuels 

that qualify for the four different 

renewable fuel standards. As mandated 

by the revised statutory requirements, 

the greenhouse gas emission 

assessments must evaluate the full 

lifecycle emission impacts of fuel 

production including both direct and 

indirect emissions, including significant 

emissions from land use changes. The 

proposed program is expected to reduce 

U.S. dependence on foreign sources of 

petroleum by increasing domestic 

sources of energy. Based on our lifecycle 

analysis, we believe that the expanded 

use of renewable fuels would provide 

significant reductions in greenhouse gas 

emissions such as carbon dioxide that 

affect climate change. We recognize the 

significance of using lifecycle 

greenhouse gas emission assessments 

that include indirect impacts such as 

emission impacts of indirect land use 

changes. Therefore, in this preamble we 

have been transparent in breaking out 

the various sources of greenhouse gas 

emissions included in the analysis and 

are seeking comments on our 

methodology as well as various options 

for determining the lifecycle greenhouse 

gas emissions (GHG) for each fuel. In 

addition to seeking comments on the 

information in this document and its 

supporting materials, the Agency is 

conducting peer reviews of critical 

aspects of the lifecycle methodology. 

The increased use of renewable fuels 

would also impact criteria pollutant 

emissions, with some pollutants such as 

volatile organic compounds (VOC) and 

nitrogen oxides (NOX) expected to 

increase and other pollutants such as 

carbon monoxide (CO) and benzene 

expected to decrease. The production of 

feedstocks used to produce renewable 

fuels is also expected to impact water 

quality. 

This action proposes regulations 

designed to ensure that refiners, 

blenders, and importers of gasoline and 

diesel would use enough renewable fuel 

each year so that the four volume 

requirements of the Energy 

Independence and Security Act would 

be met with renewable fuels that also 

meet the required lifecycle greenhouse 

gas emissions performance standards. 

Our proposed rule describes the 

standards that would apply to these 

parties and the renewable fuels that 

would qualify for compliance. The 

proposed regulations make a number of 

changes to the current Renewable Fuel 

Standard program while retaining many 

elements of the compliance and trading 

system already in place. 

DATES: Comments must be received on 

or before July 27, 2009, 60 days after 

publication in the Federal Register. 

Under the Paperwork Reduction Act, 

comments on the information collection 

provisions are best assured of having 

full effect if the Office of Management 

and Budget (OMB) receives a copy of 

your comments on or before June 25, 

2009, 30 days after date of publication 

in the Federal Register. 

Hearing: We will hold a public 

hearing on June 9, 2009 at the Dupont 

Hotel in Washington, DC. The hearing 

will start at 10 a.m. local time and 

continue until everyone has had a 

chance to speak. If you want to testify 

at the hearing, notify the contact person 

listed under FOR FURTHER INFORMATION

CONTACT by June 1, 2009. 

Workshop: We will hold a workshop 

on June 10–11, 2009 at the Dupont Hotel 

in Washington, DC to present details of 

our lifecycle GHG analysis. During this 

workshop, we intend to go through the 

lifecycle GHG analysis included in this 

proposal. The intent of this workshop is 

to help ensure a full understanding of 

our lifecycle analysis, the major issues 

identified and the options discussed. 

We expect that this workshop will help 

ensure that we receive submission of the 

most thoughtful and useful comments to 

this proposal and that the best 

methodology and assumptions are used 

for calculating GHG emissions impacts 

of fuels for the final rule. While this 

workshop will be held during the 

comment period, it is not intended to 

replace either the formal public hearing 

or the need to submit comments to the 

docket. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2005–0161, by one of the 

following methods: 

• www.regulations.gov: Follow the 

on-line instructions for submitting 

comments. 

• E-mail: asdinfo@epa.gov. 

• Mail: Air and Radiation Docket and 

Information Center, Environmental 

Protection Agency, Mailcode: 2822T, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460. In addition, 

please mail a copy of your comments on 

the information collection provisions to 

the Office of Information and Regulatory 

Affairs, Office of Management and 

Budget (OMB), Attn: Desk Officer for 

EPA, 725 17th St., NW., Washington, DC 

20503. 

• Hand Delivery: EPA Docket Center, 

EPA West Building, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC 20004. Such deliveries are only 

accepted during the Docket’s normal 

hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2005– 

0161. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or e-mail. The www.regulations.gov 

Web site is an ‘‘anonymous access’’ 

system, which means EPA will not 

know your identity or contact 

information unless you provide it in the 

body of your comment. If you send an 

e-mail comment directly to EPA without 

going through www.regulations.gov 

your e-mail address will be 

automatically captured and included as 

part of the comment that is placed in the 

public docket and made available on the 

Internet. If you submit an electronic 

comment, EPA recommends that you 

include your name and other contact 

information in the body of your 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24905 

comment and with any disk or CD–ROM 

you submit. If EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. Electronic files should avoid 

the use of special characters, any form 

of encryption, and be free of any defects 

or viruses. For additional information 

about EPA’s public docket visit the EPA 

Docket Center homepage at http:// 

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

For additional instructions on 

submitting comments, go to Section XI, 

Public Participation, of the 

SUPPLEMENTARY INFORMATION section of 

this document. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available, e.g., CBI or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket and 

Information Center, EPA/DC, EPA West, 

Room 3334, 1301 Constitution Ave., 

NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

Hearing: The public hearing will be 

held on June 9, 2009 at the Dupont 

Hotel, 1500 New Hampshire Avenue, 

NW., Washington, DC 20036. See 

Section XI, Public Participation, for 

more information about the public 

hearing. 

FOR FURTHER INFORMATION CONTACT: Julia 

MacAllister, Office of Transportation 

and Air Quality, Assessment and 

Standards Division, Environmental 

Protection Agency, 2000 Traverwood 

Drive, Ann Arbor, MI 48105; Telephone 

number: 734–214–4131; Fax number: 

734–214–4816; E-mail address: 

macallister.julia@epa.gov, or 

Assessment and Standards Division 

Hotline; telephone number (734) 214– 

4636; E-mail address asdinfo@epa.gov. 

SUPPLEMENTARY INFORMATION: 

General Information 

A. Does This Proposal Apply to Me? 

Entities potentially affected by this 

proposal are those involved with the 

production, distribution, and sale of 

transportation fuels, including gasoline 

and diesel fuel or renewable fuels such 

as ethanol and biodiesel. Regulated 

categories include: 

Category NAICS1

codes 

SIC 2

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. 

1 North American Industry Classification System (NAICS). 2 Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this proposed action. This 

table lists the types of entities that EPA 

is now aware could potentially be 

regulated by this proposed action. Other 

types of entities not listed in the table 

could also be regulated. To determine 

whether your activities would be 

regulated by this proposed action, you 

should carefully examine the 

applicability criteria in 40 CFR part 80. 

If you have any questions regarding the 

applicability of this proposed action to 

a particular entity, consult the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

B. What Should I Consider as I Prepare 

My Comments for EPA? 

1. Submitting CBI 

Do not submit this information to EPA 

through www.regulations.gov or e-mail. 

Clearly mark the part or all of the 

information that you claim to be 

confidential business information (CBI). 

For CBI information in a disk or CD– 

ROM that you mail to EPA, mark the 

outside of the disk or CD–ROM as CBI 

and then identify electronically within 

the disk or CD–ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. 

Information so marked will not be 

disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

2. Tips for Preparing Your Comments 

When submitting comments, 

remember to: 

• Explain your views as clearly as 

possible. 

• Describe any assumptions that you 

used. 

• Provide any technical information 

and/or data you used that support your 

views. 

• If you estimate potential burden or 

costs, explain how you arrived at your 

estimate. 

• Provide specific examples to 

illustrate your concerns. 

• Offer alternatives. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

• To ensure proper receipt by EPA, 

identify the appropriate docket 

identification number in the subject line 

on the first page of your response. It 

would also be helpful if you provided 

the name, date, and Federal Register 

citation related to your comments. 

We are primarily seeking comment on 

the proposed 40 CFR Part 80 Subpart M 

regulatory language that is not directly 

included in 40 CFR Part 80 Subpart K. 

For the proposed subpart M regulatory 

language that is unchanged from subpart 

K, we are only soliciting comment as it 

relates to its use for the RFS2 rule. 

Outline of This Preamble 

I. Introduction 

A. Renewable Fuels and the Transportation 

Sector 

24906 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

B. Renewable Fuels and Greenhouse Gas 

Emissions 

C. Building on the RFS1 Program 

II. Overview of the Proposed Program 

A. Summary of New Provisions of the RFS 

Program 

1. Required Volumes of Renewable Fuel 

2. Changes in How Renewable Fuel Is 

Defined 

3. Analysis of Lifecycle Greenhouse Gas 

Emissions and Thresholds for Renewable 

Fuels 

4. Coverage Expanded to Transportation 

Fuel, Including Diesel and Nonroad 

Fuels 

5. Effective Date for New Requirements 

6. Treatment of Required Volumes 

Preceding the RFS2 Effective Date 

7. Waivers and Credits for Cellulosic 

Biofuel 

8. Proposed Standards for 2010 

B. Impacts of Increasing Volume 

Requirements in the RFS2 Program 

1. Greenhouse Gases and Fossil Fuel 

Consumption 

2. Economic Impacts and Energy Security 

3. Emissions, Air Quality, and Health 

Impacts 

4. Water 

5. Agricultural Commodity Prices 

III. What Are the Major Elements of the 

Program Required Under EISA? 

A. Changes to Renewable Identification 

Numbers (RINs) 

B. New Eligibility Requirements for 

Renewable Fuels 

1. Changes in Renewable Fuel Definitions 

a. Renewable Fuel and Renewable Biomass 

b. Advanced Biofuel 

c. Cellulosic Biofuel 

d. Biomass-Based Diesel 

e. Additional Renewable Fuel 

2. Lifecycle GHG Thresholds 

3. Renewable Fuel Exempt From 20 

Percent GHG Threshold 

a. Definition of Commence Construction 

b. Definition and Boundaries of a Facility 

c. Options Proposed in Today’s 

Rulemaking 

i. Basic Approach: Grandfathering Limited 

to Baseline Volumes 

(1) Increases in volume of renewable fuel 

produced at grandfathered facilities due 

to expansion 

(2) Replacements of equipment 

(3) Registration, Recordkeeping and 

Reporting 

(4) Sub-option of treatment of future 

modifications 

ii. Alternative Options for Which We Seek 

Comment 

(1) Facilities that meet the definition of 

‘‘reconstruction’’ are considered new 

(2) Expiration date of 15 years for 

exempted facilities 

(3) Expiration date of 15 years for 

grandfathered facilities and limitation on 

volume 

(4) ‘‘Significant production units’’ are 

defined as facilities 

(5) Indefinite grandfathering and no 

limitations placed on volume 

4. Renewable Biomass with Land 

Restrictions 

a. Definitions of Terms 

i. Planted Crops and Crop Residue 

ii. Planted Trees and Tree Residue 

iii. Slash and Pre-Commercial Thinnings 

iv. Biomass Obtained From Certain Areas 

at Risk From Wildfire 

b. Issues Related to Implementation and 

Enforceability 

i. Ensuring That RINs Are Generated Only 

for Fuels Made From Renewable Biomass 

ii. Ensuring That RINs Are Generated for 

All Qualifying Renewable Fuel 

c. Review of Existing Programs 

i. USDA Programs 

ii. Third-Party Programs 

d. Approaches for Domestic Renewable 

Fuel 

e. Approaches for Foreign Renewable Fuel 

C. Expanded Registration Process for 

Producers and Importers 

1. Domestic Renewable Fuel Producers 

2. Foreign Renewable Fuel Producers 

3. Renewable Fuel Importers 

4. Process and Timing 

D. Generation of RINs 

1. Equivalence Values 

2. Fuel Pathways and Assignment of D 

Codes 

a. Domestic Producers 

b. Foreign Producers 

c. Importers 

3. Facilities With Multiple Applicable 

Pathways 

4. Facilities That Co-Process Renewable 

Biomass and Fossil Fuels 

5 Treatment of Fuels Without an 

Applicable D Code 

6. Carbon Capture and Storage (CCS) 

E. Applicable Standards 

1. Calculation of Standards 

a. How Would the Standards Be 

Calculated? 

b. Proposed Standards for 2010 

c. Projected Standards for Other Years 

d. Alternative Effective Date 

2. Treatment of Biomass-Based Diesel in 

2009 and 2010 

a. Proposed Shift in Biomass-Based Diesel 

Requirement from 2009 to 2010 

i. First Option for Treatment of 2009 

Biodiesel and Renewable Diesel RINs 

ii. Second Option for Treatment of 2009 

Biodiesel and Renewable Diesel RINs 

b. Proposed Treatment of Deficit 

Carryovers and Valid RIN Life for 

Adjusted 2010 Biomass-Based Diesel 

Requirement 

c. Alternative Approach to Treatment of 

Biomass-Based Diesel in 2009 and 2010 

F. Fuels That Are Subject to the Standards 

1. Gasoline 

2. Diesel 

3. Other Transportation Fuels 

G. Renewable Volume Obligations (RVOs) 

1. Determination of RVOs Corresponding to 

the Four Standards 

2. RINs Eligible to Meet Each RVO 

3. Treatment of RFS1 RINs under RFS2 

a. Use of 2009 RINs in 2010 

b. Deficit Carryovers from the RFS1 

Program to RFS2 

4. Alternative Approach to Designation of 

Obligated Parties 

H. Separation of RINs 

1. Nonroad 

2. Heating Oil and Jet Fuel 

3. Exporters 

4. Alternative Approaches to RIN Transfers 

5. Neat Renewable Fuel and Renewable 

Fuel Blends Designated as 

Transportation Fuel, Home Heating Oil, 

or Jet Fuel 

I. Treatment of Cellulosic Biofuel 

1. Cellulosic Biofuel Standard 

2. EPA Cellulosic Allowances for 

Cellulosic Biofuel 

3. Potential Adverse Impacts of Allowances 

J. Changes to Recordkeeping and Reporting 

Requirements 

1. Recordkeeping 

2. Reporting 

3. Additional Requirements for Producers 

of Renewable Natural Gas, Electricity, 

and Propane 

K. Production Outlook Reports 

L. What Acts Are Prohibited and Who Is 

Liable for Violations? 

IV. What Other Program Changes Have We 

Considered? 

A. Attest Engagements 

B. Small Refinery and Small Refiner 

Flexibilities 

1. Small Refinery Temporary Exemption 

2. Small Refiner Flexibilities 

a. Extension of Existing RFS1 Temporary 

Exemption 

b. Program Review 

c. Extensions of the Temporary Exemption 

Based on Disproportionate Economic 

Hardship 

d. Phase-in 

e. RIN-Related Flexibilities 

C. Other Flexibilities 

1. Upward Delegation of RIN-Separating 

Responsibilities 

2. Small Producer Exemption 

D. 20% Rollover Cap 

E. Concept for EPA Moderated Transaction 

System 

2. How EMTS Would Work 

3. Implementation of EMTS 

F. Retail Dispenser Labelling for Gasoline 

with Greater than 10 Percent Ethanol 

V. Assessment of Renewable Fuel Production 

Capacity and Use 

A. Summary of Projected Volumes 

1. Reference Case 

2. Control Case for Analyses 

a. Cellulosic Biofuel 

b. Biomass-Based Diesel 

c. Other Advanced Biofuel 

d. Other Renewable Fuel 

B. Renewable Fuel Production 

1. Corn/Starch Ethanol 

a. Historic/Current Production 

b. Forecasted Production Under RFS2 

2. Cellulosic Ethanol 

a. Current Production/Plans 

b. Federal/State Production Incentives 

c. Feedstock Availability 

i Urban Waste 

ii. Agricultural and Forestry Residues 

iii Dedicated Energy Crops 

iv. Summary of Cellulosic Feedstocks for 

2022 

v. Cellulosic Plant Siting 

3. Imported Ethanol 

a. Historic World Ethanol Production and 

Consumption 

b. Historic/Current Domestic Imports 

c. Projected Domestic Imports 

4. Biodiesel & Renewable Diesel 

a. Historic and Projected Production 

i. Biodiesel 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24907 

ii. Renewable Diesel 

b. Feedstock Availability 

C. Renewable Fuel Distribution 

1. Overview of Ethanol Distribution 

2. Overview of Biodiesel Distribution 

3. Overview of Renewable Diesel 

Distribution 

4. Changes in Freight Tonnage Movements 

5. Necessary Rail System Accommodations 

6. Necessary Marine System 

Accommodations 

7. Necessary Accommodations to the Road 

Transportation System 

8. Necessary Terminal Accommodations 

9. Need for Additional E85 Retail Facilities 

D. Ethanol Consumption 

1. Historic/Current Ethanol Consumption 

2. Increased Ethanol Use under RFS2 

a. Projected Gasoline Energy Demand 

b. Projected Growth in Flexible Fuel 

Vehicles 

c. Projected Growth in E85 Access 

d. Required Increase in E85 Refueling Rates 

e. Market Pricing of E85 Versus Gasoline 

3. Other Mechanisms for Getting Beyond 

the E10 Blend Wall 

a. Mandate for FFV Production 

b. Waiver of Mid-Level Ethanol Blends 

(E15/E20) 

c. Partial Waiver for Mid-Level Blends 

d. Non-Ethanol Cellulosic Biofuel 

Production 

e. Measurement Tolerance for E10 

f. Redefining ‘‘Substantially Similar’’ to 

Allow Mid-Level Ethanol Blends 

VI. Impacts of the Program on Greenhouse 

Gas Emissions 

A. Introduction 

1. Definition of Lifecycle GHG Emissions 

2. History and Evolution of GHG Lifecycle 

Analysis 

B. Methodology 

1. Scenario Description 

2. Scope of the Analysis 

a. Legal Interpretation of Lifecycle 

Greenhouse Gas Emissions 

b. System Boundaries 

3. Modeling Framework 

4. Treatment of Uncertainty 

5. Components of the Lifecycle GHG 

Emissions Analysis 

a. Feedstock Production 

i. Domestic Agricultural Sector Impacts 

ii. International Agricultural Sector GHG 

Impacts 

b. Land Use Change 

i. Amount of Land Converted 

ii. Where Land Is Converted 

iii. What Type of Land Is Converted 

iv. What Are the GHG Emissions 

Associated with Different Types of Land 

Conversion 

v. Assessing GHG Emissions Impacts Over 

Time and Potential Application of a GHG 

Discount Rate 

c. Feedstock Transport 

d. Processing 

e. Fuel Transport 

f. Tailpipe Combustion 

6. Petroleum Baseline 

7. Energy Sector Indirect Impacts 

C. Fuel Specific GHG Emissions Estimates 

1. Greenhouse Gas Emissions Reductions 

Relative to the 2005 Petroleum Baseline 

a. Corn Ethanol 

b. Imported Ethanol 

c. Cellulosic Ethanol 

d. Biodiesel 

2. Treatment of GHG Emissions Over Time 

D. Thresholds 

E. Assignment of Pathways to Renewable 

Fuel Categories 

1. Statutory Requirements 

2. Assignments for Pathways Subjected to 

Lifecycle Analyses 

3. Assignments for Additional Pathways 

a. Ethanol From Starch 

b. Renewable Fuels from Cellulosic 

Biomass 

c. Biodiesel 

d. Renewable Diesel Through 

Hydrotreating 

4. Summary 

F. Total GHG Emission Reductions 

G. Effects of GHG Emission Reductions and 

Changes in Global Temperature and Sea 

Level 

1. Introduction 

2. Estimated Projected Reductions in 

Global Mean Surface Temperatures 

VII. How Would the Proposal Impact Criteria 

and Toxic Pollutant Emissions and Their 

Associated Effects? 

A. Overview of Impacts 

B. Fuel Production & Distribution Impacts 

of the Proposed Program 

C. Vehicle and Equipment Emission 

Impacts of Fuel Program 

D. Air Quality Impacts 

1. Current Levels of PM2.5, Ozone and Air 

Toxics 

2. Impacts of Proposed Standards on 

Future Ambient Concentrations of PM2.5, 

Ozone and Air Toxics 

E. Health Effects of Criteria and Air Toxic 

Pollutants 

1. Particulate Matter 

a. Background 

b. Health Effects of PM 

2. Ozone 

a. Background 

b. Health Effects of Ozone 

3. Carbon Monoxide 

4. Air Toxics 

a. Acetaldehyde 

b. Acrolein 

c. Benzene 

d. 1,3-Butadiene; 

e. Ethanol 

f. Formaldehyde 

g. Naphthalene 

h. Peroxyacetyl nitrate (PAN) 

i. Other Air Toxics 

F. Environmental Effects of Criteria and Air 

Toxic Pollutants 

1. Visibility 

2. Atmospheric Deposition 

3. Plant and Ecosystem Effects of Ozone 

4. Welfare Effects of Air Toxics 

VIII. Impacts on Cost of Renewable Fuels, 

Gasoline, and Diesel 

A. Renewable Fuel Production Costs 

1. Ethanol Production Costs 

a. Corn Ethanol 

b. Cellulosic Ethanol 

i. Feedstock Costs 

ii. Production Costs 

c. Imported Sugarcane Ethanol 

2. Biodiesel and Renewable Diesel 

Production Costs 

a. Biodiesel 

b. Renewable Diesel 

3. BTL Diesel Production Costs 

B. Distribution Costs 

1. Ethanol Distribution Costs 

a. Capital Costs to Upgrade the Distribution 

System for Increased Ethanol Volume 

b. Ethanol Freight Costs 

2. Biodiesel and Renewable Diesel 

Distribution Costs 

a. Capital Costs to Upgrade the Distribution 

System for Increased FAME Biodiesel 

Volume 

b. Biodiesel Freight Costs 

c. Renewable Diesel Distribution System 

Capital and Freight Costs 

C. Reduced Refining Industry Costs 

D. Total Estimated Cost Impacts 

1. Refinery Modeling Methodology 

2. Overall Impact on Fuel Cost 

a. Costs Without Federal Tax Subsidies 

b. Gasoline and Diesel Costs Reflecting the 

Tax Subsidies 

IX. Economic Impacts and Benefits of the 

Proposal 

A. Agricultural Impacts 

1. Commodity Price Changes 

2. Impacts on U.S. Farm Income 

3. Commodity Use Changes 

4. U.S. Land Use Changes 

5. Impact on U.S. Food Prices 

6. International Impacts 

B. Energy Security Impacts 

1. Implications of Reduced Petroleum Use 

on U.S. Imports 

2. Energy Security Implications 

a. Effect of Oil Use on Long-Run Oil Price, 

U.S. Import Costs, and Economic Output 

b. Short-Run Disruption Premium from 

Expected Costs of Sudden Supply 

Disruptions 

c. Costs of Existing U.S. Energy Security 

Policies 

d. Anticipated Future Effort 

e. Total Energy Security Benefits 

C. Benefits of Reducing GHG Emissions 

1. Introduction 

2. Marginal GHG Benefits Estimates 

3. Discussion of Marginal GHG Benefits 

Estimates 

4. Total Monetized GHG Benefits Estimates 

D. Co-pollutant Health and Environmental 

Impacts 

1. Human Health and Environmental 

Impacts 

2. Monetized Impacts 

3. Other Unquantified Health and 

Environmental Impacts 

E. Economy-Wide Impacts 

X. Impacts on Water 

A. Background 

1. Ecological Impacts 

2. Gulf of Mexico 

B. Upper Mississippi River Basin Analysis 

1. SWAT Model 

2. Baseline Model Scenario 

3. Alternative Scenarios 

C. Additional Water Issues 

1. Chesapeake Bay Watershed 

2. Ethanol Production 

a. Distillers Grain with Solubles 

b. Ethanol Leaks and Spills 

3. Biodiesel Plants 

4. Water Quantity 

5. Drinking Water 

D. Request for Comment on Options for 

Reducing Water Quality Impacts 

XI. Public Participation 

24908 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

1See Section IV.D of EPA’s advanced notice of 

proposed rulemaking, Regulating Greenhouse Gas 

Emissions under the Clean Air Act, for a discussion 

of EPA’s possible authority under section 211(c) of 

the CAA to establish GHG standards for renewable 

and alternative fuels. 73 FR 44354, July 30, 2008. 

A. How Do I Submit Comments? 

B. How Should I Submit CBI to the 

Agency? 

C. Will There Be a Public Hearing? 

D. Comment Period 

E. What Should I Consider as I Prepare My 

Comments for EPA? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

1. Overview 

2. Background 

3. Summary of Potentially Affected Small 

Entities 

4. Potential Reporting, Record Keeping, 

and Compliance 

5. Related Federal Rules 

6. Summary of SBREFA Panel Process and 

Panel Outreach 

a. Significant Panel Findings 

b. Panel Process 

c. Panel Recommendations 

i. Delay in Standards 

ii. Phase-in 

iii. RIN-Related Flexibilities 

iv. Program Review 

v. Extensions of the Temporary Exemption 

Based on a Study of Small Refinery 

Impacts 

vi. Extensions of the Temporary Exemption 

Based on Disproportionate Economic 

Hardship 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

XIII. Statutory Authority 

I. Introduction 

The current Renewable Fuel Standard 

program (RFS1) was originally adopted 

by EPA to implement the provisions of 

the Energy Policy Act of 2005 (EPAct), 

which added section 211(o) to the Clean 

Air Act (CAA). With the passage of the 

Energy Independence and Security Act 

of 2007 (EISA), Congress recently made 

several important revisions to these 

renewable fuel requirements. This 

Notice proposes to revise the RFS 

program regulations to implement these 

EISA provisions. The proposed changes 

would apply starting January 1, 2010. 

For the remainder of 2009, the current 

RFS1 regulations would apply. 

However, in anticipation of the biomassbased diesel standard proposed for 

2010, obligated parties may find it in 

their best interest to plan accordingly in 

2009. 

A. Renewable Fuels and the 

Transportation Sector 

For the past several years, U.S. 

renewable fuel use has been rapidly 

increasing for a number of reasons. In 

the early 1990’s, certain oxygenated 

gasoline fuel programs required by the 

CAA amendments of 1990 established 

new market opportunities for renewable 

fuels, primarily ethanol. At the same 

time, growing concern over U.S. 

dependence on foreign sources of crude 

placed increasing focus on renewable 

fuels as a replacement for petroleumbased fuels. More recently, several state 

bans on the use of methyl tertiary butyl 

ether (MTBE) in gasoline resulted in a 

large, sudden increase in demand for 

ethanol. Perhaps the largest impact on 

renewable fuel demand, however, has 

been the dramatic increase in the cost of 

crude oil. In the last few years, both 

crude oil prices and crude oil price 

forecasts have increased dramatically, 

which have resulted in a large economic 

incentive for the increased development 

and use of renewable fuels. 

In 2005, Congress introduced a new 

approach to supporting renewable fuels. 

EPAct established a major new federal 

renewable fuel volume mandate. EPAct 

required a ramp up to 7.5 billion gallons 

of renewable fuel as motor vehicle fuel 

by 2012 and set annual volume targets 

for each year leading up to 2012. For 

2013 and beyond, EPA was directed to 

establish the annual required renewable 

fuel volumes, but at a percentage level 

no less than that required for 2012. 

While the market forces described above 

ultimately caused renewable fuel use to 

far exceed the EPAct mandates, this 

program provided certainty that at least 

a minimum amount of renewable fuel 

would be used in the U.S. transportation 

market, which in turn provided 

assurance for investment in production 

capacity. 

The subsequent passage of EISA made 

significant changes to both the structure 

and the magnitude of the renewable fuel 

program. The renewable fuel program 

established by EISA, hereafter referred 

to as RFS2, mandates the use of 36 

billion gallons of renewable fuel by 

2022. This is nearly a five-fold increase 

over the highest volume specified by 

EPAct and constitutes a 10-year 

extension of the scheduled production 

ramp-up period provided for in that 

legislation. It is clear that the volumes 

required by EISA will push the market 

to new levels—far beyond what current 

market conditions would achieve alone. 

In addition, EISA specifies four separate 

categories of renewable fuels, each with 

a separate volume mandate. The 

categories are renewable fuel, advanced 

biofuel, biomass-based diesel, and 

cellulosic biofuel. There is a notable 

increase in the mandate for cellulosic 

biofuels in particular. EISA increased 

the cellulosic biofuel mandate from 250 

million in EPAct to 1.0 billion gallons 

by 2013, with additional yearly 

increases to 16 billion gallons by 2022. 

These requirements will provide a 

strong foundation for investment in 

cellulosic production and position 

cellulosic fuel to become a major 

portion of the renewable fuel pool over 

the next decade. 

The implications of the volume 

expansion of the program are not trivial. 

Development of infrastructure capable 

of delivering, storing and blending these 

volumes in new markets and expanding 

existing market capabilities will be 

needed. For example, the market’s 

absorption of increased volumes of 

ethanol may ultimately require new 

‘‘outlets’’ beyond E10 blends (i.e., 

gasoline containing 10% ethanol by 

volume), such as an expansion of the 

number of flexible-fuel E85 vehicles and 

the number of retail outlets selling E85. 

B. Renewable Fuels and Greenhouse Gas 

Emissions 

Another significant aspect of the RFS2 

program is the focus on the greenhouse 

gas impact of renewable fuels, from a 

lifecycle perspective. The lifecycle GHG 

emissions means the aggregate quantity 

of GHGs related to the full fuel cycle, 

including all stages of fuel and 

feedstock production and distribution, 

from feedstock generation and 

extraction through distribution and 

delivery and use of the finished fuel. 

EISA established specific greenhouse 

gas emission thresholds for each of four 

types of renewable fuels, requiring a 

percentage improvement compared to a 

baseline of the gasoline and diesel used 

in 2005. EPA must conduct a lifecycle 

analysis to determine whether or not 

renewable fuels produced under varying 

conditions will meet the greenhouse gas 

(GHG) thresholds for the different fuel 

types for which EISA establishes 

mandates. While these thresholds do 

not constitute a control on greenhouse 

gases for transportation fuels (such as a 

low carbon fuel standard),1 they do 

require that the volume mandates be 

met through the use of renewable fuels 

that meet certain lifecycle GHG 

reduction thresholds when compared to 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24909 

2To meet the requirements of EPAct, EPA had 

previously adopted a limited program that applied 

only to calendar year 2006. The RFS1 program 

refers to the general program adopted in the May 

2007 rulemaking. 

the baseline lifecycle emissions of 

petroleum fuel they replace. 

Compliance with the thresholds 

requires a comprehensive evaluation of 

renewable fuels, as well as of gasoline 

and diesel, on the basis of their lifecycle 

emissions. As mandated by EISA, the 

greenhouse gas emission assessments 

must evaluate the full lifecycle emission 

impacts of fuel production including 

both direct and indirect emissions, 

including significant emissions from 

land use changes. We recognize the 

significance of using lifecycle 

greenhouse gas emission assessments 

that include indirect impacts such as 

emission impacts of indirect land use 

changes. Therefore, in this preamble, we 

have been transparent in breaking out 

the various sources of greenhouse gas 

emissions included in the analysis. As 

described in detail in Section VI, EPA 

has analyzed the lifecycle GHG impacts 

of the range of biofuels currently 

expected to contribute significantly to 

meeting the volume mandates of EISA 

through 2022. In these analyses we have 

used the best science available. Our 

analysis relies on peer reviewed models 

and the best estimate of important 

trends in agricultural practices and fuel 

production technologies as these may 

impact our prediction of individual 

biofuel GHG performance through 2022. 

We have identified and highlighted 

assumptions and model inputs that 

particularly influence our assessment 

and seek comment on these 

assumptions, the models we have used 

and our overall methodology so as to 

assure the most robust assessment of 

lifecycle GHG performance for the final 

rule. 

Because lifecycle analysis is a new 

part of the RFS program, in addition to 

the formal comment period on the 

proposed rule, EPA is making multiple 

efforts to solicit public and expert 

feedback on our proposed approach. 

EPA plans to hold a public workshop 

focused specifically on lifecycle 

analysis during the comment period to 

assure full understanding of the 

analyses conducted, the issues 

addressed and the options that are 

discussed. We expect that this 

workshop will help ensure that we 

receive submission of the most 

thoughtful and useful comments to this 

proposal and that the best methodology 

and assumptions are used for 

calculating GHG emissions impacts of 

fuels for the final rule. Additionally, 

between this proposal and the final rule, 

we will conduct peer-reviews of key 

components of our analysis. As 

explained in more detail in the Section 

VI, EPA is specifically seeking peer 

review of: Our use of satellite data to 

project future the type of land use 

changes; the land conversion GHG 

emissions factors estimates we have 

used for different types of land use; our 

estimates of GHG emissions from 

foreign crop production; methods to 

account for the variable timing of GHG 

emissions; and how the several models 

we have relied upon are used together 

to provide overall lifecycle GHG 

estimates. 

In addition to the GHG thresholds, 

EISA included several provisions for the 

RFS2 program designed to address the 

long-term environmental sustainability 

of expanded biofuels production. The 

new law limits the crops and crop 

residues used to produce renewable fuel 

to those grown on land cleared or 

cultivated at any time prior to 

enactment of EISA, that is either 

actively managed or fallow, and nonforested. EISA also generally requires 

that forest-related slash and tree 

thinnings used for renewable fuel 

production pursuant to the Act be 

harvested from non-federal forest lands. 

To address potential air quality 

concerns, EPA is required by section 

209 of EISA to determine whether the 

RFS2 volumes will adversely impact air 

quality as a result of changes in vehicle 

and engine emissions and then to issue 

fuel regulations that mitigate—to the 

extent achievable—these impacts. The 

Agency is also required by section 204 

of EISA to conduct a broad study of 

environmental and resource 

conservation impacts of EISA, including 

impacts on water quality and 

availability, soil conservation, and 

biodiversity. Congress set specific 

deadlines for both of these provisions, 

which are separate from this rulemaking 

and will be carried out as part of a 

future effort. However, this NPRM does 

include EPA’s initial assessment of the 

air and water quality impacts of the 

EISA volumes. 

While the above described changes 

are significant, it is important to note 

that Congress left other structural 

elements of the RFS program basically 

intact. The various modifications are 

discussed throughout this preamble. 

C. Building on the RFS1 Program 

In designing this proposed RFS2 

program, the Agency is utilizing and 

building on the same programmatic 

structure created to implement the 

current renewable fuel program 

(hereafter referred to as RFS1). For 

example, we propose to continue to use 

the Renewable Identification Number 

(RIN) system currently in place to track 

compliance with the RFS1 program, 

with modifications to implement the 

EISA provisions. This approach is in 

keeping with the Agency’s overall intent 

for RFS1—to design a flexible and 

enforceable system that could continue 

to operate effectively regardless of the 

level of renewable fuel use or market 

conditions in the transportation fuel 

sector. 

A key component of the Agency’s 

work to build a successful RFS1 

program was early and sustained 

engagement with our stakeholders. In 

developing this proposed rulemaking, 

we have again worked closely with a 

wide variety of stakeholders. Because 

EISA created new obligated parties and 

established new, complex provisions 

such as the lifecycle GHG thresholds 

and previous cropland requirements, 

EPA has extended its stakeholder 

engagement to include dozens of 

meetings with stakeholders from a broad 

spectrum of perspectives. For example, 

the Agency has had multiple meetings 

and discussions with renewable fuel 

producers, technology companies, 

petroleum refiners and importers, 

agricultural associations, lifecycle 

experts, environmental groups, vehicle 

manufacturers, states, gasoline and 

petroleum marketers, pipeline owners 

and fuel terminal operators. 

II. Overview of the Proposed Program 

This section provides an overview of 

the RFS2 program requirements that 

EPA proposes to implement as a result 

of EISA. The RFS2 program would 

replace the RFS1 program promulgated 

on May 1, 2007 (72 FR 23900).2 We are 

also proposing a number of changes to 

make the program more flexible based 

on what we learned from the operation 

of the RFS1 program since it began on 

September 1, 2007. Details of the 

proposed requirements can be found in 

Sections III and IV. We request 

comment on our proposed regulatory 

requirements and the alternatives that 

we have considered. 

This section also provides a summary 

of EPA’s impacts assessment of the use 

of higher renewable fuel volumes. 

Impacts that we assessed include: 

emissions of pollutants such as 

greenhouse gases (GHG), oxides of 

nitrogen (NOX), hydrocarbons, 

particulate matter (PM), and toxics; 

reductions in petroleum use and related 

impacts on national energy security; 

impacts on the agriculture sector; 

impacts on costs of transportation fuels; 

economic costs and benefits; and 

impacts on water. Details of these 

24910 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

analyses can be found in Sections V 

through X and in the Draft Regulatory 

Impact Analysis (DRIA). 

A. Summary of New Provisions of the 

RFS Program 

Today’s notice proposes new 

regulatory requirements for the RFS 

program that would be implemented 

through a new Subpart M to 40 CFR Part 

80. EPA is generally proposing to 

maintain many elements of the RFS1 

program such as regulations governing 

the generation, transfer, and use of 

Renewable Identification Numbers 

(RINs). At the same time, we seek 

comment on a number of RFS1 

provisions that may require adjustment 

under an expanded RFS2 program, 

including whether or not to require that 

all qualifying renewable fuels have RINs 

generated for it (discussed in Section 

III.B.4.b.ii), and whether a rollover cap 

on RINs other than 20 percent might be 

appropriate (discussed in Section IV.D). 

Furthermore, EPA is proposing several 

new provisions and seeking comment 

on alternatives on aspects of the 

program for which EISA grants EPA 

discretion and flexibility, such as the 

grandfathering of existing renewable 

fuel production facilities (discussed in 

Section III.B.3), the potential inclusion 

of electricity for credit (discussed in 

Section III.B.1.a), and how renewable 

fuels are categorized based on the 

results of lifecycle analyses (discussed 

in Section VI.B). We believe these and 

other aspects of the program are 

important because they will affect 

available volumes of qualifying 

renewable fuel, regulated parties’ ability 

to comply with the program and, 

ultimately, the program’s environmental 

and societal impacts. A full description 

of all the changes we are proposing to 

the RFS program to implement the 

requirements in EISA is provided in 

Section III, while Section IV includes 

extensive discussion of other changes to 

the RFS program under consideration. 

1. Required Volumes of Renewable Fuel 

The primary purpose of the RFS 

program is to require a minimum 

volume of renewable fuel to be used 

each year in the transportation sector. 

Under RFS1, the required volume was 

4.0 billion gallons in 2006, ramping up 

to 7.5 billion gallons by 2012. Starting 

in 2013, EPAct required that the total 

volume of renewable fuel represent at 

minimum the same volume fraction of 

the gasoline fuel pool as it did in 2012, 

and that the total volume of renewable 

fuel contains at least 250 million gallons 

of fuel derived from cellulosic biomass. 

EISA makes three primary changes to 

the volume requirements of the RFS 

program. First, it substantially increases 

the required volumes and extends the 

timeframe over which the volumes ramp 

up through at least 2022. Second, it 

divides the total renewable fuel 

requirement into four separate 

categories, each with its own volume 

requirement. Third, it requires that each 

of these mandated volumes of 

renewable fuels achieve certain 

minimum thresholds of GHG emission 

performance. The volume requirements 

in EISA are shown in Table II.A.1–1. 

TABLE II.A.1–1—RENEWABLE FUEL VOLUME REQUIREMENTS FOR RFS2 

[Billion gallons] 

Cellulosic 

biofuel 

requirement 

Biomassbased diesel 

requirement 

Advanced 

biofuel 

requirement 

Total 

renewable fuel 

requirement 

2009 ................................................................................................................. n/a 0.5 0.6 11.1 

2010 ................................................................................................................. 0.1 0.65 0.95 12.95 

2011 ................................................................................................................. 0.25 0.80 1.35 13.95 

2012 ................................................................................................................. 0.5 1.0 2.0 15.2 

2013 ................................................................................................................. 1.0 a 2.75 16.55 

2014 ................................................................................................................. 1.75 a 3.75 18.15 

2015 ................................................................................................................. 3.0 a 5.5 20.5 

2016 ................................................................................................................. 4.25 a 7.25 22.25 

2017 ................................................................................................................. 5.5 a 9.0 24.0 

2018 ................................................................................................................. 7.0 a 11.0 26.0 

2019 ................................................................................................................. 8.5 a 13.0 28.0 

2020 ................................................................................................................. 10.5 a 15.0 30.0 

2021 ................................................................................................................. 13.5 a 18.0 33.0 

2022 ................................................................................................................. 16.0 a 21.0 36.0 

2023+ ............................................................................................................... b b b b

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

As shown in the table, the volume 

requirements are not exclusive, and 

generally result in nested requirements. 

Any renewable fuel that meets the 

requirement for cellulosic biofuel or 

biomass-based diesel is also valid for 

meeting the advanced biofuel 

requirement. Likewise, any renewable 

fuel that meets the requirement for 

advanced biofuel is also valid for 

meeting the total renewable fuel 

requirement. See Section VI.E for 

further discussion of which specific 

types of fuel meet the requirements for 

one of the four categories shown in 

Table II.A.1–1. 

We are co-proposing and taking 

comment on two options for how to 

treat the volumes of different renewable 

fuels for purposes of complying with the 

volume mandates of RFS2: As either 

ethanol-equivalent gallons, based on 

energy content, as finalized in the RFS1 

program, or as actual volume in gallons. 

Consideration of the actual volume 

option would recognize that EISA now 

guarantees a market for specific 

categories of renewable fuel and assigns 

a GHG requirement to each category in 

the form of minimum GHG thresholds 

that each must meet. The approach 

taken in RFS1 would continue to assign 

value, in terms of gallons, to all 

renewable fuels based on their energy 

value in comparison with ethanol. 

Further discussion of the rationale and 

implications of these two approaches 

can be found in Section III.D.1. 

The statutorily-prescribed phase-in 

period ends in 2012 for biomass-based 

diesel and in 2022 for cellulosic biofuel, 

advanced biofuel, and total renewable 

fuel. Beyond these years, EISA requires 

EPA to determine the applicable 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24911 

volumes based on a review of the 

implementation of the program up to 

that time, and an analysis of a wide 

variety of factors such as the impact of 

the production of renewable fuels on the 

environment, energy security, 

infrastructure, costs, and other factors. 

For these future standards, EPA must 

promulgate rules establishing the 

applicable volumes no later than 14 

months before the first year for which 

such applicable volumes would apply. 

For biomass-based diesel, this would 

mean that final rules would need to be 

issued by October 31, 2011 for 

application starting on January 1, 2013. 

In today’s proposed rulemaking, we are 

not suggesting any specific volume 

requirements for biomass-based diesel 

for 2013 and beyond that would be 

appropriate under the statutory criteria 

that we must consider. Likewise, we are 

not suggesting any specific volume 

requirements for the other three 

renewable fuel categories for 2023 and 

beyond. However, the statute requires 

that the biomass-based diesel volume in 

2013 and beyond must be no less than 

1.0 billion gallons, and that advanced 

biofuels in 2023 and beyond must 

represent at a minimum the same 

percentage of total renewable fuel as it 

does in 2022. 

2. Changes in How Renewable Fuel Is 

Defined 

Under the existing Renewable Fuel 

Standard, (RFS1) renewable fuel is 

defined generally as ‘‘any motor vehicle 

fuel that is used to replace or reduce the 

quantity of fossil fuel present in a fuel 

mixture used to fuel a motor vehicle’’. 

The RFS1 definition includes motor 

vehicle fuels produced from biomass 

material such as grain, starch, fats, 

greases, oils and biogas. 

The definitions of renewable fuels 

under today’s proposed rule (RFS2) are 

based on the new statutory definitions 

in EISA. Like the existing rules, the 

definitions in RFS2 include a general 

definition of renewable fuel, but unlike 

RFS1, we are including a separate 

definition of ‘‘Renewable Biomass’’ 

which identifies the feedstocks from 

which renewable fuels may be made. 

Another difference in the definitions 

of renewable fuel is that RFS2 contains 

three subcategories of renewable fuels: 

(1) Advanced Biofuel, (2) Cellulosic 

Biofuel and (3) Biomass-Based Diesel. 

‘‘Advanced Biofuel’’ is a renewable 

fuel other than ethanol derived from 

corn starch and which must achieve a 

lifecycle GHG emission displacement of 

50%, compared to the gasoline or diesel 

fuel it displaces. 

Cellulosic biofuel is any renewable 

fuel, not necessarily ethanol, derived 

from any cellulose, hemicellulose, or 

lignin each of which must originate 

from renewable biomass. It must 

achieve a lifecycle GHG emission 

displacement of 60%, compared to the 

gasoline or diesel fuel it displaces for it 

to qualify as cellulosic biofuel. 

The RFS1 definition provided that 

ethanol made at any facility—regardless 

of whether cellulosic feedstock is used 

or not—may be defined as cellulosic if 

at such facility ‘‘animal wastes or other 

waste materials are digested or 

otherwise used to displace 90% or more 

of the fossil fuel normally used in the 

production of ethanol.’’ This provision 

was not included in EISA, and therefore 

does not appear in the definitions 

pertaining to cellulosic biofuel in 

today’s proposed rule. 

The statutory definition of ‘‘renewable 

biomass’’ in EISA does not include a 

reference to municipal solid waste 

(MSW) as did the definition of 

‘‘cellulosic biomass ethanol’’ in EPAct, 

but instead includes ‘‘separated yard 

waste and food waste. EPA’s proposed 

definition of renewable biomass in 

today’s proposed rule includes the 

language present in EISA. As discussed 

in Section III.B.1.a, we invite comment 

on whether this definition should be 

interpreted as including or excluding 

MSW containing yard and/or food waste 

from the definition of renewable 

biomass. EPA intends to resolve this 

matter in the final rule, and EPA solicits 

comment on the approach that it should 

take. 

Under today’s proposed rule 

‘‘Biomass-based diesel’’ includes 

biodiesel (mono-alkyl esters), non-ester 

renewable diesel and any other diesel 

fuel made from renewable biomass, as 

long as they are not ‘‘co-processed’’ with 

petroleum. EISA requires that such fuel 

achieve a lifecycle GHG emission 

displacement of 50%, compared to the 

gasoline or diesel fuel it displaces. As 

discussed in Section III.B.1.d, we are 

proposing that co-processing is 

considered to occur only if both 

petroleum and biomass feedstock are 

processed in the same unit 

simultaneously. Thus, if serial batch 

processing in which 100% vegetable oil 

is processed one day/week/month and 

100% petroleum the next day/week/ 

month occurs, the fuel derived from 

renewable biomass would be assigned 

RINs with a D code identifying it as 

biomass-based diesel. The resulting 

products could be blended together, but 

only the volume produced from 

renewable biomass would count as 

biomass-based diesel. 

For other renewable fuels, EISA 

makes a distinction between fuel from 

new and existing facilities. Only 

renewable fuel from new facilities is 

required to achieve a lifecycle GHG 

emission displacement of 20%. As 

discussed in Section III.B.3, this 

requirement applies only to renewable 

fuel that is produced from certain 

facilities which commenced 

construction after December 19, 2007. 

EISA defines ‘‘additional renewable 

fuel’’ as fuel produced from renewable 

biomass that is used to replace or reduce 

fossil fuels used in home heating oil or 

jet fuel. The Act provides that EPA may 

allow for the generation of RFS credits 

for such fuel. This represents a change 

from RFS1, where renewable fuel 

qualifying for credits was limited to fuel 

used in motor vehicles. We propose to 

modify the regulatory requirements to 

allow RINs assigned to renewable fuel 

blended into heating oil or jet fuel to be 

valid for compliance purposes. The fuel 

would still have to meet all the other 

criteria to qualify as a renewable fuel, 

including being made from renewable 

biomass. For example, RINs generated 

for advanced biofuel or biomass-based 

diesel that could be used in automobiles 

would still be valid, and would not 

need to be retired, if the fuel producer 

instead sells the fuels for use in heating 

oil or jet fuel. 

‘‘Renewable biomass’’ is defined in 

EISA to include a number of feedstock 

types, such as planted crops and crop 

residue, planted trees and tree residue, 

animal waste, algae, and yard and food 

waste. However, the EISA definition 

limits many of these feedstocks 

according to the management practices 

for the land from which they are 

derived. For example, planted crops and 

crop residue must be harvested from 

agricultural land cleared or cultivated at 

any time prior to December 19, 2007, 

that is actively managed or fallow, and 

non-forested. Therefore, planted crops 

and crop residue derived from land that 

does not meet this definition cannot be 

used to produce renewable fuel for 

credit under RFS2. 

Under today’s proposed rule, we 

describe several options for ensuring 

that feedstocks used to produce 

renewable fuel for which credits are 

generated under RFS2 meet the 

definition of renewable biomass. Our 

proposed approach places overall 

responsibility for verifying a feedstock’s 

source on the party who generates a RIN 

for the renewable fuel produced from 

the feedstock. We also present options 

for how a party could or should verify 

his or her feedstock, and we seek 

comment on these options. A full 

discussion of the definition and 

implementation options for ‘‘renewable 

biomass’’ is presented in Section III.B.4. 

24912 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

3. Analysis of Lifecycle Greenhouse Gas 

Emissions and Thresholds for 

Renewable Fuels 

As shown in Table II.A.3–1, EISA 

requires that a renewable fuel must meet 

minimum thresholds for their reduction 

in lifecycle greenhouse gas emissions: A 

20% reduction in lifecycle GHG 

emissions for any renewable fuel 

produced at new facilities; a 50% 

reduction in order to be classified as 

biomass-based diesel or advanced 

biofuel; and a 60% reduction in order to 

be classified as cellulosic biofuel. The 

lifecycle GHG emissions means the 

aggregate quantity of GHG emissions 

related to the full fuel cycle, including 

all stages of fuel and feedstock 

production and distribution, from 

feedstock generation or extraction 

through distribution and delivery and 

use of the finished fuel. As mandated by 

EISA, it includes direct emissions and 

significant indirect emissions such as 

significant emissions from land use 

changes. EPA believes that compliance 

with the EISA mandate—determining 

the aggregate GHG emissions related to 

the full fuel lifecycle, including both 

direct emissions and significant indirect 

emissions such as land use changes— 

make it necessary to assess those direct 

and indirect impacts that occur not just 

within the United States but also those 

that occur in other countries. This 

applies to determining the lifecycle 

emissions for petroleum-based fuels to 

determine the baseline, as well as the 

lifecycle emissions for biofuels. For 

biofuels, this includes evaluating 

significant emissions from indirect land 

use changes that occur in other 

countries as a result of the increased 

domestic production or importation of 

biofuels into the U.S. As detailed in 

Section VI, we have included the GHG 

emission impacts of international land 

use changes including the indirect land 

use changes that result from domestic 

production of biofuel feedstocks. We 

recognize the significance of including 

international land use emission impacts 

and, in our analysis presentation in 

Section VI, have been transparent in 

breaking out the various sources of GHG 

emissions so that the reader can readily 

see the impact of including 

international land use impacts. 

TABLE II.A.3–1—LIFECYCLE GHG 

THRESHOLDS SPECIFIED IN EISA 

[Percent reduction from baseline] 

Renewable fuel a ............................... 20 

Advanced biofuel .............................. 50 

Biomass-based diesel ...................... 50 

TABLE II.A.3–1—LIFECYCLE GHG 

THRESHOLDS SPECIFIED IN EISA— 

Continued 

[Percent reduction from baseline] 

Cellulosic biofuel ............................... 60 

aThe 20% criterion generally applies to renewable fuel from new facilities that commenced construction after December 19, 

2007. 

The lifecycle GHG emissions of the 

renewable fuel are compared to the 

lifecycle GHG emissions for gasoline or 

diesel (whichever is being replaced by 

the renewable fuel) sold or distributed 

as transportation fuel in 2005. EISA 

provides some limited flexibility for 

EPA to adjust these GHG percentage 

thresholds downward by up to 10 

percent under certain circumstances. As 

discussed in Section VI.D, we are 

proposing that the GHG threshold for 

advanced biofuels be adjusted to 44% or 

potentially as low as 40% depending on 

the results from the analyses that will be 

conducted for the final rule. This 

adjustment would allow ethanol 

produced from sugarcane to count as 

advanced biofuel and would help 

ensure that the volume mandate for 

advanced biofuel could be met. 

The regulatory purpose of the 

lifecycle greenhouse gas emissions 

analysis is to determine whether 

renewable fuels meet the GHG 

thresholds for the different categories of 

renewable fuel. As described in detail in 

Section VI, EPA has analyzed the 

lifecycle GHG impacts of the range of 

biofuels currently expected to 

contribute significantly to meeting the 

volume mandates of EISA through 2022. 

In these analyses we have used the best 

science available. Our analysis relies on 

peer reviewed models and the best 

estimate of important trends in 

agricultural practices and fuel 

production technologies as these may 

impact our prediction of individual 

biofuel GHG performance through 2022. 

We have identified and highlighted 

assumptions and model inputs that 

particularly influence our assessment 

and seek comment on these 

assumptions, the models we have used 

and our overall methodology so as to 

assure the most robust assessment of 

lifecycle GHG performance for the final 

rule. 

In addition to the many technical 

issues addressed in this proposal, 

Section VI discusses the emissions 

decreases and increases associated with 

the different parts of the lifecycle 

emissions of various biofuels and the 

timeframes in which these emissions 

changes occur. The need to determine a 

single lifecycle value that best 

represents this combination of 

emissions increases and decreases 

occurring over time led EPA to consider 

various alternative ways to analyze the 

timeframe of emissions changes related 

to biofuel production and use as well as 

options for adjusting or discounting 

these emissions to determine their net 

present value. Section VI highlights two 

options. One option assumes a 30 year 

time period for assessing future GHG 

emissions impacts of the anticipated 

increase in biofuel production to meet 

the mandates of EISA, both emissions 

increases and decreases, and values all 

these emission impacts the same 

regardless of when they occur during 

that time period (i.e., no discounting). 

The second option assesses emissions 

impacts over a 100 year time period but 

then discounts future emissions 2% 

annually to arrive at an estimate of a net 

present value of those emissions. 

Several other variations of time period 

and discount rate are also discussed. 

The analytical time horizon and the 

choice whether to discount GHG 

emissions and, if so, at what appropriate 

rate can have a significant impact on the 

final assessment of the lifecycle GHG 

emissions impacts of individual biofuels 

as well as the overall GHG impacts of 

these EISA provisions and this rule. 

We believe that our lifecycle analysis 

is based on the best available science 

and recognize that in some aspects it 

represents a cutting edge approach to 

addressing lifecycle GHG emissions. 

Because of the varying degrees of 

uncertainty in the different aspects of 

our analysis, we conducted a number of 

sensitivity analyses which focus on key 

parameters and demonstrate how our 

assessments might change under 

alternative assumptions. By focusing 

attention on these key parameters, the 

comments we receive as well as 

additional investigation and analysis by 

EPA will allow narrowing of uncertainty 

concerns for the final rule. In addition 

to this sensitivity analysis approach, we 

will also explore options for more 

formal uncertainty analyses for the final 

rule to the extent possible. 

Because lifecycle analysis is a new 

part of the RFS program, in addition to 

the formal comment period on the 

proposed rule, EPA is making multiple 

efforts to solicit public and expert 

feedback on our proposed approach. 

EPA plans to hold a public workshop 

focused specifically on lifecycle 

analysis during the comment period to 

assure full understanding of the 

analyses conducted, the issues 

addressed and the options that are 

discussed. We expect that this 

workshop will help ensure that we 

receive submission of the most 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24913 

thoughtful and useful comments to this 

proposal and that the best methodology 

and assumptions are used for 

calculating GHG emissions impacts of 

fuels for the final rule. Additionally, 

between this proposal and the final rule, 

we will conduct peer reviews of key 

components of our analysis. As 

explained in more detail in Section VI, 

EPA is specifically seeking peer review 

of: Our use of satellite data to project 

future types of land use changes; the 

land conversion GHG emissions factors 

estimates we have used for different 

types of land use; our estimates of GHG 

emissions from foreign crop production; 

methods to account for the variable 

timing of GHG emissions; and how the 

several models we have relied upon are 

used together to provide overall 

lifecycle GHG estimates. 

Some renewable fuel is not required 

to meet the 20% GHG threshold. Section 

211(o)(2)(A) provides that only 

renewable fuel produced from new 

facilities which commenced 

construction after December 19, 2007 

must meet the 20% threshold. Facilities 

that commenced construction on or 

before December 19, 2007 are exempt or 

‘‘grandfathered’’ from the 20% 

threshold requirement. In addition, 

section 210(a) of EISA provides a further 

exemption from the 20% threshold 

requirement for ethanol plants that 

commenced construction in 2008 or 

2009 and are fired with natural gas, 

biomass, or any combination thereof. 

The renewable fuel from such facilities 

is deemed to be in compliance with the 

20% threshold, and would thus also be 

‘‘grandfathered.’’ 

We are proposing and taking 

comment on one approach to the 

grandfathering provisions in today’s 

rule, and seeking comment on five 

additional options. The proposed 

approach would provide an indefinite 

time period for grandfathering status but 

with restrictions to the baseline volume 

of renewable fuel that is grandfathered. 

The alternative options are (1) 

Expiration of exemption for 

grandfathered status when facilities 

undergo sufficient changes to be 

considered ‘‘reconstructed’’; (2) 

Expiration of exemption 15 years after 

EISA enactment, industry-wide; (3) 

Expiration of exemption 15 years after 

EISA enactment with limitation of 

exemption to baseline volume; (4) 

‘‘Significant’’ production components 

are treated as facilities and 

grandfathered or deemed compliant 

status ends when they are replaced; and 

(5) Indefinite exemption and no 

limitations placed on baseline volumes. 

Our proposal and the alternative options 

are discussed in further detail in Section 

III.B.3.c. 

While renewable fuels would be 

required to meet the GHG thresholds 

shown in Table II.A.3–1 in order to be 

valid for compliance purposes under the 

RFS2 program, we are not proposing 

that an individual facility-specific 

lifecycle GHG emissions value would 

have to be determined in order to show 

that the biofuel produced or imported at 

an individual facility complies with the 

threshold. Instead, EPA has determined 

lifecycle GHG values for specific 

combinations of fuel type, feedstock, 

and production process, using average 

values for various lifecycle model 

inputs. As a result of these assessments, 

we propose to assign each combination 

of fuel type, feedstock, and production 

process to one of the four renewable fuel 

categories specified in EISA or, 

alternatively, make a determination that 

the biofuel combination has been 

disqualified from generating RINs 

(except as may be allowed for 

grandfathered renewable fuel) due to a 

failure to meet the minimum 20% GHG 

threshold. Section VI.E discusses our 

proposed assignments. We are also 

proposing a mechanism to allow 

biofuels whose lifecycle GHG emissions 

have not been assessed to participate in 

the RFS program under certain limited 

conditions. These conditions are 

described in Section III.D.5. 

4. Coverage Expanded to Transportation 

Fuel, Including Diesel and Nonroad 

Fuels 

EPAct only mandated the blending of 

renewable fuels into gasoline, though it 

gave credit for renewable fuels blended 

into diesel fuel. EISA expanded the 

program to generally cover 

transportation fuel, which is defined as 

fuel for use in motor vehicles, motor 

vehicle engines, nonroad vehicles, or 

nonroad engines. This includes diesel 

fuel intended for use in highway 

vehicles and engines, and nonroad, 

locomotive, and marine engines and 

vessels, as well as gaseous or other fuels 

used in these vehicles, engines, or 

vessels. EISA also specifies that 

‘‘transportation fuels’’ do not include 

fuels for use in ocean-going vessels. 

EPA is required to ensure that 

transportation fuel contains at least the 

specified volumes of renewable fuel. 

Under EISA, renewable fuel now 

includes fuel that is used to displace 

fossil fuel present in transportation fuel, 

and as in RFS1, EPA is required to 

determine the refiners, blenders, and 

importers of transportation fuel that are 

subject to the renewable volume 

obligation. As discussed in Section III.F, 

while we are seeking comment on 

alternatives, EPA is proposing 

consistent with RFS1 that these 

provisions could best be met by 

requiring that the renewable volume 

obligation apply to refiners, blenders, 

and importers of motor vehicle or 

nonroad gasoline or diesel (with limited 

flexibilities for small refineries and 

small refiners), and that their percentage 

obligation would apply to the amount of 

gasoline or diesel they produce for such 

use. We propose to use the current 

definition of motor vehicle, nonroad, 

locomotive, and marine diesel fuel 

(MVNRLM)—as defined at § 80.2(qqq)— 

to determine the obligated volumes of 

non-gasoline transportation fuel for this 

rule. 

We request comment on these aspects 

of our proposed program. 

5. Effective Date for New Requirements 

Under CAA section 211(o) as 

modified by EISA, EPA is required to 

revise the RFS1 regulations within one 

year of enactment, or December 19, 

2008. Promulgation by this date would 

have been consistent with the revised 

volume requirements shown in Table 

II.A.1–1 that begin in 2009 for certain 

categories of renewable fuel. However, 

due to the addition of complex lifecycle 

assessments to the determination of 

eligibility of renewable fuels, the 

extensive analysis of impacts that we 

are conducting for the higher renewable 

fuel volumes, the various complex 

changes to the regulatory program that 

require close collaboration with 

stakeholders, and various statutory 

limitations such as the Small Business 

Regulatory Enforcement Flexibility Act 

(SBREFA) and a 60 day Congressional 

review period for all significant actions, 

we were not able to promulgate final 

RFS2 program requirements by 

December 19, 2008. As a result, we are 

proposing that the RFS2 regulatory 

program go into effect on January 1, 

2010. 

In order to successfully implement 

the RFS2 program, parties that generate 

RINs, own and/or transfer them, or use 

them for compliance purposes will need 

to re-register under the RFS2 provisions 

and modify their information 

technology (IT) systems to accommodate 

the changes we are proposing today. As 

described more fully in Section III, these 

changes would include redefining the D 

code within the RIN, adding a process 

for verifying that feedstocks meet the 

renewable biomass definition, and 

calculating compliance with four 

standards instead of one. Regulated 

parties will need to establish new 

contractual relationships to cover the 

different types of renewable fuel 

required under RFS2. Parties that 

24914 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

3 73 FR 70643, November 21, 2008. 

produce MVNRLM diesel but not 

gasoline will be newly obligated parties 

and may be establishing IT systems for 

the RFS program for the first time. For 

RFS1, regulated parties had four months 

between promulgation of the final 

rulemaking on May 1, 2007 and the start 

of the program on September 1, 2007. 

However, this was for a new program 

that had not existed before. For the 

RFS2 program, most regulated parties 

will already be familiar with the general 

requirements for RIN generation, 

transfer, and use, and the attendant 

recordkeeping and reporting 

requirements. We believe that with 

proper attention to the implementation 

requirements by regulated parties, the 

RFS2 program can be implemented on 

January 1, 2010 following release of the 

final rule. 

Although we are proposing that the 

RFS2 regulatory program begin on 

January 1, 2010, we seek comment on 

whether a start date later than January 

1, 2010 would be necessary. Alternative 

effective dates for the RFS2 program 

include January 1, 2011 and a date after 

January 1, 2010 but before January 1, 

2011. We are requesting comment on all 

issues related to such an alternative 

effective date, including the need for 

such a delayed start, treatment of diesel 

producers and importers, whether the 

standards for advanced biofuel, 

cellulosic biofuel and biomass-based 

diesel should apply to the entire 2010 

production or just the production that 

would occur after the RFS2 effective 

date, and the extent to which RFS1 RINs 

should be valid to show compliance 

with RFS2 standards. Further 

discussion of alternative effective dates 

for RFS2 can be found in Section 

III.E.1.d. 

6. Treatment of Required Volumes 

Preceding the RFS2 Effective Date 

We are proposing that the RFS2 

regulatory program begin on January 1, 

2010. Under CAA section 211(o), the 

requirements for refiners, blenders, and 

importers (called ‘‘obligated parties’’) as 

well as the requirements for producers 

of renewable fuel and others, stem from 

the regulatory provisions adopted by 

EPA. In effect while EPAct and EISA 

both call for EPA to issue regulations 

that achieve certain results, the various 

regulated parties are not subject to these 

requirements until EPA issues the 

regulations establishing their 

obligations. The changes brought about 

by EISA, such as the 4 separate 

standards, the lifecycle GHG thresholds, 

changes to obligated parties, and the 

revised definition of renewable biomass 

do not become effective until today’s 

proposal is finalized. Rather, the current 

RFS1 regulations continue to apply 

until EPA amends them to implement 

EISA, and any delay in issuance of the 

RFS2 regulations means that parties 

would continue to be subject to the 

RFS1 regulations until the RFS2 

regulations were in effect. Therefore, 

regulated parties would continue to be 

subject to the existing regulations at 40 

CFR Part 80 Subpart K through 

December 31, 2009, or later if the 

effective date of the RFS2 program were 

later than January 1, 2010. 

Under the RFS1 regulations the 

annual percentage standards that are 

applicable to obligated parties are 

determined by a formula set forth in the 

regulations. The formula uses gasoline 

volume projections from the Energy 

Information Administration (EIA) and 

the required volume of renewable fuel 

provided in Clean Air Act section 

211(o)(2)(B). Since EISA modified the 

required volumes in this section of the 

Clean Air Act, EPA believes that the 

new statutory volumes can be used 

under the RFS1 regulations in 

generating the standards for 2009. 

Therefore, in November 2008 we used 

the new total renewable fuel volume of 

11.1 billion gallons as the basis for the 

2009 standard, and not the 6.1 billion 

gallons that was required by EPAct.3

While this approach will ensure that 

the total renewable fuel volume of 11.1 

billion gallons required by EISA for 

2009 will be used, the RFS1 regulatory 

structure does not provide a mechanism 

for implementing the 0.5 billion gallon 

requirement for biomass-based diesel 

nor the 0.6 billion gallon requirement 

for advanced biofuel. As described in 

more detail in Section III.E.2, we are 

proposing to address this issue by 

increasing the 2010 biomass-based 

diesel requirement by 0.5 billion gallons 

and allowing 2009 biodiesel and 

renewable diesel RINs to be used to 

meet this combined 2009/2010 

requirement. Doing so would also allow 

most of the 2009 advanced biofuel 

requirement to be met. We believe this 

would provide a similar incentive for 

biomass-based diesel use in 2009 as 

would have occurred had we been able 

to implement this standard for 2009. We 

propose that this requirement would 

apply to all obligated parties under 

RFS2, including producers and 

importers of diesel fuel. 

As noted above, EPA is proposing a 

start date for the RFS2 program of 

January 1, 2010, and is also seeking 

comment on alternative start dates of 

sometime during 2010 or January 1, 

2011. If the start date is other than 

January 1, 2010, EPA would need to 

determine what renewable fuel volumes 

to require in the interim between 

January 1, 2010 and the start of the 

RFS2 program. While we could apply 

the same approach, described above, 

that we have used for 2009, doing so 

could mean that 2009 biodiesel RINs 

would be valid for compliance purposes 

in 2011, which would run counter to the 

statutory valid life of two years. 

Nevertheless, we request comment on 

whether this potential approach or 

another approach is warranted based on 

the differing volumes and types of 

renewable fuel specified for use in EISA 

for 2010. 

7. Waivers and Credits for Cellulosic 

Biofuel 

Section 202(e) of EISA provides that 

for any calendar year in which the 

projected volume of cellulosic biofuel 

production is less than the minimum 

applicable volume required by the 

statute, EPA will waive a portion of the 

cellulosic biofuel standard by using the 

projected volume as the basis for setting 

the applicable standard. In this event, 

EISA also allows but does not require 

EPA to reduce the required volume of 

advanced biofuel and total renewable 

fuel. The process of projecting the 

volume of cellulosic biofuel that may be 

produced in the next year, and the 

associated process of determining 

whether and to what degree the 

advanced biofuel and total renewable 

fuel requirements should be lowered, 

will involve considerations that extend 

beyond the simple calculation based on 

gasoline demand that was used to set 

the annual standards under RFS1. As a 

result, we believe that this process 

should be subject to a notice-andcomment rulemaking process. 

Moreover, since we must make these 

determinations every year for 

application to the following year, we 

expect to conduct these rulemakings 

every year. 

In determining whether the advanced 

biofuel and/or total renewable fuel 

volume requirements should also be 

adjusted downward in the event that 

projected volumes of cellulosic biofuel 

fall short of the statutorily required 

volumes, we believe it would be 

appropriate to allow excess advanced 

biofuels to make up some or all of the 

shortfall in cellulosic biofuel. For 

instance, if we determined that 

sufficient biomass-based diesel was 

available, we could decide that the 

required volume of advanced biofuel 

need not be lowered, or that it should 

be lowered to a smaller degree than the 

required cellulosic biofuel volume. We 

would then lower the total renewable 

fuel volume to the same degree that we 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24915 

would lower the advanced biofuel 

volume. We do not believe it would be 

appropriate to lower the advanced 

biofuel standard but not the total 

renewable standard, as this would allow 

conventional biofuels to effectively be 

used to meet the standards Congress 

specifically set for cellulosic and 

advanced biofuels. 

If EPA reduces the required volume of 

cellulosic biofuel, EPA must offer a 

number of credits no greater than the 

reduced cellulosic biofuel standard. 

EISA dictates the cost of these credits 

and ties them to inflation. The Act also 

dictates that we must promulgate 

regulations on the use of these credits 

and offers guidance on how these 

credits may be offered and used. We 

propose that their uses will be very 

limited. The credits would not be 

allowed to be traded or banked for 

future use, but would be allowed to 

meet the cellulosic biofuel standard, 

advanced biofuel standard and total 

renewable fuel standard. Further 

discussion of the implementation of 

these provisions can be found in Section 

III.I. 

8. Proposed Standards for 2010 

Once the RFS2 program is 

implemented, we expect to conduct a 

notice-and-comment rulemaking 

process each year in order to determine 

the appropriate standards applicable in 

the following year. We therefore intend 

to issue an NPRM in the spring and a 

final rule by November 30 of each year 

as required by statute. 

However, for the 2010 compliance 

year, today’s action provides a means 

for seeking comment on the applicable 

standards. Therefore, rather than issuing 

a separate NPRM for the 2010 standard, 

we are proposing the 2010 standards in 

today’s notice. We will consider 

comments received during the comment 

period associated with today’s NPRM, 

and we expect to issue a Federal 

Register notice by November 30, 2009 

setting the applicable standards for 

2010. 

We propose that the RFS2 program be 

effective on January 1, 2010. Therefore, 

all EISA volume mandates for 2010 

would be implemented in that year, 

unless EPA exercised its authority to 

waive one or more of the standards. 

Based on information from the industry, 

we believe that there are sufficient plans 

underway to build plants capable of 

producing 0.1 billion gallons of 

cellulosic biofuel in 2010, the minimum 

volume of cellulosic biofuel required by 

EISA for 2010. However, we recognize 

that cellulosic biofuel is at the very 

earliest stages of commercialization and 

current economic concerns could have 

significant impacts on these near term 

plans. Therefore, while based on 

industry plans available to EPA, we are 

not proposing that any portion of the 

cellulosic biofuel requirement for 2010 

be waived, we are seeking additional 

and updated information that would be 

available prior to November 30, 2009 

which could result in a change in this 

conclusion. Similarly, we are not aware 

of the need to waive any other volume 

mandates for 2010. Therefore, we are 

proposing that the volumes shown in 

Table II.A.1–1 for all four renewable 

fuel categories be used as the basis for 

the applicable standards for 2010. The 

proposed standards are shown in Table 

II.A.8–1, each representing the fraction 

of a refiner’s or importer’s gasoline and 

diesel volume which must be renewable 

fuel. 

TABLE II.A.8–1—PROPOSED

STANDARDS FOR 2010 

[Percent] 

Cellulosic biofuel ............................... 0.06 

Biomass-based diesel ...................... 0.71 

Advanced biofuel .............................. 0.59 

Renewable fuel ................................. 8.01 

Note that the proposed 2010 

standards shown in Table II.A.8–1 were 

based on currently available projections 

of 2010 gasoline and diesel volumes. 

The final standards will be calculated 

on the basis of gasoline and diesel 

volume projections from the Energy 

Information Administration’s (EIA) 

Short-Term Energy Outlook and 

published by November 30, 2009. 

Additional discussion of our proposed 

2010 standards can be found in Section 

III.E.1.b. 

Note also that the proposed standards 

assume an effective date of January 1, 

2010 for RFS2. We are taking comment 

on alternative effective dates for RFS2, 

including January 1, 2011 and a date 

after January 1, 2010 but before January 

1, 2011. Such alternative effective dates 

would raise issues with regard to the 

calculation and application of the 

standards for total renewable fuel and 

the other standards required under 

EISA, as well as the generation and 

application of RINs under RFS1 and 

RFS2. As described more fully in 

Section III.E.1.d, we request comment 

on the issues associated with alternative 

effective dates for RFS2. 

B. Impacts of Increasing Volume 

Requirements in the RFS2 Program 

The displacement of gasoline and 

diesel with renewable fuels has a wide 

range of environmental and economic 

impacts. As we describe below, we have 

assessed many of these impacts for the 

RFS2 proposal and we will have more 

complete assessments, including a costbenefit comparison, for the final rule. 

These assessments provide important 

information to the wider public policy 

considerations of renewable fuels, 

climate change, and national energy 

security. They are also an important 

component of all significant 

rulemakings. 

However, because the volumes of 

renewable fuel were specified by 

statute, they would not be based on or 

revised by our analysis of impacts. In 

addition, because we have very limited 

discretion to pursue regulatory 

alternatives, the proposal does not 

include a systematic alternatives 

analysis. We have investigated 

regulatory alternatives in some areas to 

the degree that EISA provides 

discretion. 

As one point of reference to assess the 

impacts of the volume requirements for 

the RFS2 program, we used projections 

for renewable fuel use in 2022 that EIA 

issued through their 2007 Annual 

Energy Outlook (AEO), and for 

transportation fuel consumption 

through their 2008 AEO. This reference 

case, referred to as the ‘‘AEO Reference 

Case,’’ represents a projection of the 

demand for renewable fuels prior to 

enactment of EISA while still reflecting 

the new Corporate Average Fuel 

Economy (CAFE) requirements in EISA, 

and the 2008 AEO projections for the 

future price of crude oil ($53 to $92 per 

barrel). Further discussion of the 

Reference Case can be found in Section 

V.A.1. Other points of reference include 

the renewable fuel volumes mandated 

by EPAct for the RFS1 program, 

renewable fuel use prior to 

implementation of the RFS1 program, 

and the full impacts of renewable fuel 

use compared to a petroleum-only 

economy. 

Given the short time provided by 

Congress to conduct a rulemaking, many 

of our analyses were done in parallel for 

this proposal. As a result, some analyses 

were conducted without the benefit of 

waiting for the conclusion of another 

analysis that could prove influential. 

Thus, for example, impacts on food 

prices assume that soy-based biodiesel 

and sugarcane ethanol will qualify as 

advanced fuels under the proposed 

RFS2 program, even though the analyses 

conducted for this proposal might 

preclude such eligibility. We have 

highlighted such inconsistencies in 

results and assumptions throughout the 

proposal. Additionally, since we have 

identified many issues and analytical 

options in our assessment of which 

biofuel pathways would comply with 

the GHG thresholds, the assessment we 

24916 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

conducted for this proposal may not 

reflect the final rule in all cases. We will 

be addressing these issues of analytical 

consistency between analyses more 

fully in the final rule. 

In a similar fashion, while we 

recognize uncertainty in our assessment 

of impacts of the proposed RFS2 

program, we do not present a formal, 

comprehensive analysis of uncertainty. 

For this proposal, many of the analyses 

are without precedent, and as a result 

we have identified the more uncertain 

aspects of these analyses and have 

worked to assess their potential impact 

on the results through sensitivity 

analyses. We intend to continue these 

assessments for the final rule, and 

expect that comments on this proposal 

will allow us to reduce our uncertainty 

in a number of areas. In addition to this 

sensitivity analysis approach, we will 

also explore options for more formal 

uncertainty analyses for the final rule to 

the extent possible. 

1. Greenhouse Gases and Fossil Fuel 

Consumption 

Our analyses of GHG impacts 

consider the full useful life assessment 

of the production of biofuels compared 

to the petroleum-based fuels they would 

replace. The analysis compared the AEO 

reference case transportation fuel pool 

in 2022 without the EISA mandates 

with the same fuel pool in 2022, but 

assuming the greater volumes of biofuel 

as mandated by EISA replace an energy 

equivalent amount of petroleum-based 

fuel. The incremental volumes of each 

biofuel type were then evaluated to 

determine their average impact on GHG 

emissions compared to the 2005 

baseline petroleum fuel they would be 

displacing. These average GHG emission 

reduction results can then be compared 

to the threshold performance levels for 

each fuel type. 

As a result of the transition to greater 

renewable fuel use, some petroleumbased gasoline and diesel will be 

directly replaced by renewable fuels. 

Therefore, consumption of petroleumbased fuels will be lower than it would 

be if no renewable fuels were used in 

transportation vehicles. However, a true 

measure of the impact of greater use of 

renewable fuels on petroleum use, and 

indeed on the use of all fossil fuels, 

accounts not only for the direct use and 

combustion of the finished fuel in a 

vehicle or engine, but also includes the 

petroleum use associated with 

production and transportation of that 

fuel. For instance, fossil fuels are used 

in producing and transporting 

renewable feedstocks such as plants or 

animal byproducts, in converting the 

renewable feedstocks into renewable 

fuel, and in transporting and blending 

the renewable fuels for consumption as 

motor vehicle fuel. Likewise, fossil fuels 

are used in the production and 

transportation of petroleum and its 

finished products. In order to estimate 

the true impacts of increases in 

renewable fuel use on fossil fuel use, we 

must take these steps into account. Such 

analyses are termed lifecycle analyses. 

The definition of lifecycle greenhouse 

gas emissions in EISA requires the 

Agency to look broadly at lifecycle 

analyses and to develop a methodology 

that accounts for the significant 

secondary or indirect impacts of 

expanded biofuels use. These indirect 

effects include both the domestic and 

international impact of land use change 

from increased biofuel feedstock 

production and the secondary 

agricultural sector GHG impacts from 

increased biofuel feedstock production 

(e.g., changes in livestock emissions due 

to changes in agricultural commodity 

prices). Today no single model can 

capture all of the complex interactions 

required to conduct a complete lifecycle 

assessment as required by Congress. As 

a result, the methodology EPA has 

currently evaluated uses a number of 

models and tools to provide a 

comprehensive estimate of GHG 

emissions. We have used a combination 

of peer reviewed models including 

Argonne National Laboratory’s GREET 

model, Texas A&M’s Forestry and 

Agricultural Sector Optimization Model 

(FASOM) and Iowa State University’s 

Food and Agricultural Policy Research 

Institute’s (FAPRI) international 

agricultural models as well as the 

Winrock International database to 

estimate lifecycle GHG emissions 

estimates. These models are described 

in more detail in Section VI and have 

been used in combination to provide the 

lifecycle GHG estimates presented in 

this proposal. However, we recognize 

other models and sources of information 

can also be used and these are also 

discussed in Section VI. 

Based on the combined use of these 

models we have estimated the lifecycle 

GHG emissions for a number of 

pathways for producing the increased 

volumes of renewable fuels as mandated 

by EISA. Section VI of this proposal 

outlines the approach taken and 

describes the key assumptions and 

parameters used in this analysis. In 

addition, this section highlights the 

impacts of varying these key inputs on 

the overall results. 

We estimate the greater volumes of 

biofuel mandated by RFS2 will reduce 

lifecycle GHG emissions from 

transportation by approximately 6.8 

billion tons of CO2 equivalent emissions 

when accounting for all the emissions 

changes over 100 years and then 

discounting this emission stream by 2% 

per year. This is equivalent to an 

average annualized emission rate of 160 

million metric tons of CO2-eq. emissions 

per year over the entire 100 year 

modeling time frame if that average 

annualized emission rate is also 

discounted at 2% per year. Determining 

lifecycle GHG emissions values for 

renewable fuels using a 0% discount 

rate over 30 years would result in an 

estimated total reduction of 4.5 billion 

tons of CO2-eq. over the 30 year period 

or an average annualized emission rate 

reduction of 150 million metric tons of 

CO2-eq. GHG emissions per year. (See 

Section VI.F of this preamble for 

additional information on how these 

emission reductions were calculated). 

Our analysis of the petroleum 

consumption impacts took a similar 

lifecycle approach. For the year 2022, 

we estimate that the 36 billion gallons 

of renewable fuel mandated by these 

rules will increase renewable fuel usage 

by approximately 22 billion gallons 

which will displace about 15 billion 

gallons of petroleum-based gasoline and 

diesel fuel. This represents about 8% of 

annual oil consumed by the 

transportation sector in 2022. 

2. Economic Impacts and Energy 

Security 

The substantially increased volumes 

of renewable fuel that would be 

required under RFS2 would produce a 

variety of different economic impacts. 

These would include changes in the 

cost of gasoline and diesel, a reduction 

in nationwide expenditures on 

petroleum imports and the associated 

increase in energy security, and 

increases in the prices of agricultural 

commodities such as corn and soybeans. 

The RFS program is projected to 

significantly impact the cost of gasoline 

and diesel, though the estimated costs 

vary based on the price of crude oil that 

is assumed. In our analysis we used 

both $92 and $53 per barrel crude oil 

based on price projections made by EIA. 

At these two crude oil price points, we 

estimate that gasoline costs would 

increase by about 2.7 and 10.9 cents per 

gallon, respectively, by 2022. Likewise, 

diesel fuel costs could experience a 

small cost reduction of 0.1 cents per 

gallon, or increase by about 1.2 cent per 

gallon, respectively. For the nation as a 

whole, these costs are equivalent to $4 

and $18 billion in 2022, respectively (in 

2006 dollars, and amortizing capital 

costs using a 7% before-tax rate of 

return). These costs represent the 

nationwide average impacts including 

the costs of producing and distributing 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24917 

4RFS1 base and mandated ethanol levels were 

projected to remain essentially unchanged in 2022 

due to the flat energy demands projected by EIA. 

both renewable fuels and gasoline and 

diesel, as well as blending costs, but 

without consideration of either the tax 

subsidies and import tariff for ethanol or 

tax subsidies for biodiesel and 

renewable diesel fuel. 

EPA’s estimates of economic impacts 

of fuels do not consider other societal 

benefits. For example, the displacement 

of petroleum-based fuel (largely 

imported) by renewable fuel (largely 

produced in the United States), should 

reduce our consumption of imported oil 

and fuel. We estimate that 91% of the 

lifecycle petroleum reductions resulting 

from the use of renewable fuel will be 

met through reductions in net 

petroleum imports. In Section IX of this 

preamble we estimate the value of the 

decrease in imported petroleum at about 

$12.4 billion in 2022 due to increased 

volumes of renewable fuels mandated 

by RFS2 in comparison to the AEO 

reference case. Net U.S. expenditures on 

petroleum imports in 2022 are projected 

to be about $208 billion. 

Furthermore, the above estimate of 

reduced U.S. petroleum import 

expenditures only partly assesses the 

economic impacts of this proposal. One 

of the effects of increased use of 

renewable fuel is that it diversifies the 

energy sources used in making 

transportation fuel. To the extent that 

diverse sources of fuel energy reduce 

the U.S. dependence on any one source, 

the risks, both financial as well as 

strategic, of a potential disruption in 

supply of a particular energy source are 

reduced. EPA has worked with 

researchers at Oak Ridge National 

Laboratory (ORNL) to update a study 

they previously published that has been 

used or cited in several government 

actions impacting U.S. oil consumption. 

This updated study went through an 

independent, third-party peer review 

process and a final draft report of this 

updated study was developed. This 

peer-reviewed report is being made 

available in the docket at this time for 

further consideration. Using the 

updated ORNL estimate, the total energy 

security benefits associated with a 

reduction of U.S. imported oil is $12.38 

per barrel of imported oil that is 

reduced. Based on these values, we 

estimate that the total annual energy 

security benefits would be $3.7 billion 

in 2022 (in 2006 dollars). 

We recognize that our current energy 

security analysis does not take into 

account risk-shifting that might occur as 

the U.S. reduces its dependency on 

petroleum by increasing its use of 

biofuels. For example, our analysis did 

not take into account other energy 

security implications associated with 

biofuels, such as possible supply 

disruptions of corn-based ethanol. We 

will attempt to broaden our energy 

security analysis to incorporate 

estimates of overall motor fuel supply 

and demand flexibility and reliability 

for the final rule, along with impacts of 

possible agricultural sector market 

disruptions. A complete discussion of 

the Agency’s plans for this analysis can 

be found in Section IX.B.2. of this 

preamble. 

While increased use of renewable fuel 

will reduce expenditures on imported 

oil, it will also increase expenditures on 

renewable fuels and in turn on the 

sources of those renewable fuels. The 

RFS program is likely to spur the 

increased use of renewable 

transportation fuels made principally 

from agricultural crops and it is 

expected that most of these crops will 

be produced in the U.S. As a result, it 

is important to analyze the 

consequences of the transition to greater 

renewable fuel use in the U.S. 

agricultural sector. To analyze the 

domestic agricultural sector impacts, 

EPA selected the Forest and 

Agricultural Sector Optimization Model 

(FASOM) developed by Professor Bruce 

McCarl of Texas A&M University and 

others over the past thirty years. 

FASOM is a dynamic, nonlinear 

programming model of the agriculture 

and forestry sectors of the U.S. 

In Section IX of this preamble, we 

estimate the change in the price of 

various agricultural products as a result 

of this rulemaking. By 2022, we estimate 

the price of corn would increase by 

$0.15 per bushel (4.6%) above the 

Reference Case price of $3.19 per 

bushel. By 2022, U.S. soybean prices 

would increase by $0.29 per bushel 

(2.9%) above the Reference Case price of 

$9.97 per bushel. Due to higher 

commodity prices, FASOM estimates 

that U.S. food costs would increase by 

$10 per person per year by 2022, 

relative to the Reference Case. Total 

farm gate food costs would increase by 

$3.3 billion (0.2%) in 2022. As a result 

of increased renewable fuel 

requirements, FASOM predicts that net 

U.S. farm income would increase by 

$7.1 billion dollars in 2022 (10.6%), 

relative to the Reference Case. 

Due to higher commodity prices, 

FASOM estimates that U.S. corn exports 

would drop from 2.7 billion bushels 

under the Reference Case to 2.4 billion 

bushels (a 10% decrease) by 2022. In 

value terms, U.S. exports of corn would 

fall by $487 million in 2022. FASOM 

estimates that U.S. exports of soybeans 

would decrease from 1.03 billion 

bushels to 943 million bushels (an 8% 

decrease) in 2022. In value terms, U.S. 

exports of soybeans would decrease by 

$691 million in 2022. 

Assuming current subsidies remain in 

place, the Renewable Fuels Standard, by 

encouraging the use of biofuels, will 

result in an expansion of subsidy 

payments by the U.S. government. If 

this resulting loss of tax revenue were 

offset by an increase in taxes, this could 

have a distortionary impact on the 

economy. We intend to consider the 

impact of the expansion of biofuel 

subsidies associated with the RFS2 in 

the context of the economy-wide 

modeling to be conducted for the final 

rule. 

We note that the economic analyses 

that support this proposal do not reflect 

all of the potentially quantifiable 

economic impacts. There are several key 

impacts that remain incomplete as a 

result of time and resource constraints, 

including the economic impact analysis 

(see Section IX) and the air quality and 

health impacts analysis (see Section 

II.B.3). As a result, this proposal does 

not combine economic impacts in an 

attempt to compare costs and benefits, 

in order to avoid presenting an 

incomplete and potentially misleading 

characterization. For the final rule, 

when the planned analyses are complete 

and current analyses updated, we will 

provide a consistent cost-benefit 

comparison. 

3. Emissions, Air Quality, and Health 

Impacts 

Analysis of criteria and toxic emission 

impacts was performed relative to three 

different reference case ethanol 

volumes, ranging from 3.64 to 13.2 

billion gallons per year. To assess the 

total impact of the RFS program, 

emissions were analyzed relative to the 

RFS1 rule base case of 3.64 billion 

gallons in 2004. To assess the impact of 

today’s RFS2 proposal relative to the 

current mandated volumes, we analyzed 

impacts relative to RFS1 mandate of 7.5 

billion gallons of renewable fuel use by 

2012, which was estimated to include 

6.7 billion gallons of ethanol.4 In order 

to assess the impact of today’s proposal 

relative to the level of ethanol projected 

to be used in 2022 without RFS2, the 

AEO2007 projection of 13.2 billion 

gallons of ethanol in 2022 was analyzed. 

We are also presenting a range of 

impacts meant to bracket the impacts of 

ethanol blends on light-duty vehicle 

emissions. Similar to the approach 

presented in the RFS1 rule, we present 

a ‘‘less sensitive’’ and ‘‘more sensitive’’ 

case to present a range of the possible 

24918 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

emission impacts of E10 on recent 

model year light duty gasoline vehicles. 

As detailed in Section VII.C, ‘‘less 

sensitive’’ does not apply any E10 

effects to NOX or HC emissions for later 

model year vehicles, or E85 effects for 

any pollutant, while ‘‘more sensitive’’ 

does. 

Our projected emission impacts for 

the ‘‘less sensitive’’ and ‘‘more 

sensitive’’ cases are shown in Table 

II.B.3–1 and II.B.3–2, showing the 

expected emission changes for the U.S. 

in 2022, and the percent contribution of 

this impact relative to the total U.S. 

inventory across all sectors. Overall we 

project the proposed program will result 

in significant increases in ethanol and 

acetaldehyde emissions—increasing the 

total U.S inventories of these pollutants 

by up to 30–40% in 2022 relative to the 

RFS1 mandate case. We project more 

modest but still significant increases in 

acrolein, NOX, formaldehyde and PM. 

We project today’s action will result in 

decreased ammonia emissions (due to 

reductions in livestock agricultural 

activity), decreased CO emissions 

(driven primarily by the impacts of 

ethanol on exhaust emissions from 

vehicles and nonroad equipment), and 

decreased benzene emissions (due to 

displacement of gasoline with ethanol 

in the fuel pool). Discussion and a 

breakdown of these results by the fuel 

production/distribution and vehicle and 

equipment emissions are presented in 

Section VII. 

TABLE II.B.3–1—RFS2 ‘‘LESS SENSITIVE’’ CASE EMISSION IMPACTS IN 2022 RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual short 

tons 

% of total U.S. 

inventory 

Annual short 

tons 

% of total U.S. 

inventory 

Annual short 

tons 

% of total U.S. 

inventory 

NOX .......................................................... 312,400 2.8 274,982 2.5 195,735 1.7 

HC ............................................................ 112,401 1.0 72,362 0.6 ¥8,193 ¥0.07 

PM10 ......................................................... 50,305 1.4 37,147 1.0 9,276 0.3 

PM2.5 ........................................................ 14,321 0.4 11,452 0.3 5,376 0.16 

CO ............................................................ ¥2,344,646 ¥4.4 ¥1,669,872 ¥3.1 ¥240,943 ¥0.4 

Benzene ................................................... ¥2,791 ¥1.7 ¥2,507 ¥1.5 ¥1,894 ¥1.1 

Ethanol ..................................................... 210,680 36.5 169,929 29.4 83,761 14.5 

1,3-Butadiene ........................................... 344 2.9 255 2.1 65 0.5 

Acetaldehyde ........................................... 12,516 33.7 10,369 27.9 5,822 15.7 

Formaldehyde .......................................... 1,647 2.3 1,348 1.9 714 1.0 

Naphthalene ............................................. 5 0.03 3 0.02 ¥1 ¥0.01 

Acrolein .................................................... 290 5.0 252 4.4 174 3.0 

SO2 ........................................................... 28,770 0.3 4,461 0.05 ¥47,030 ¥0.5 

NH3 ........................................................... ¥27,161 ¥0.6 ¥27,161 ¥0.6 ¥27,161 ¥0.6 

TABLE II.B.3–2—RFS2 ‘‘MORE SENSITIVE’’ CASE EMISSION IMPACTS IN 2022 RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual short 

tons 

% of total U.S. 

inventory 

Annual short 

tons 

% of total U.S. 

inventory 

Annual short 

tons 

% of total U.S. 

inventory 

NOX .......................................................... 402,795 3.6 341,028 3.0 210,217 1.9 

HC ............................................................ 100,313 0.9 63,530 0.6 ¥15,948 ¥0.14 

PM10 ......................................................... 46,193 1.3 33,035 0.9 5,164 0.15 

PM2.5 ........................................................ 10,535 0.3 7,666 0.2 1,589 0.05 

CO ............................................................ ¥3,779,572 ¥7.0 ¥3,104,798 ¥5.8 ¥1,675,869 ¥3.1 

Benzene ................................................... ¥5,962 ¥3.5 ¥5,494 ¥3.3 ¥4,489 ¥2.7 

Ethanol ..................................................... 228,563 39.6 187,926 32.5 105,264 18.2 

1,3-Butadiene ........................................... ¥212 ¥1.8 ¥282 ¥2.4 ¥430 ¥3.6 

Acetaldehyde ........................................... 16,375 44.0 14,278 38.4 9,839 26.5 

Formaldehyde .......................................... 3,373 4.7 3,124 4.3 2,596 3.6 

Naphthalene ............................................. ¥175 ¥1.2 ¥178 ¥1.3 ¥187 ¥1.3 

Acrolein .................................................... 253 4.4 218 3.8 143 2.5 

SO2 ........................................................... 28,770 0.3 4,461 0.05 ¥47,030 ¥0.5 

NH3 ........................................................... ¥27,161 ¥0.6 ¥27,161 ¥0.6 ¥27,161 ¥0.6 

We note that the aggregate nationwide 

emission inventory impacts presented 

here will likely lead to health impacts 

throughout the U.S. due to changes in 

future-year ambient air quality. 

However, emissions changes alone are 

not a good indication of local or regional 

air quality and health impacts, as there 

may be highly localized impacts such as 

increased emissions from ethanol plants 

and evaporative emissions from cars, 

and decreased emissions from gasoline 

refineries. In addition, the atmospheric 

chemistry related to ambient 

concentrations of PM2.5, ozone and air 

toxics is very complex, and making 

predictions based solely on emissions 

changes is extremely difficult. Full-scale 

photochemical modeling is necessary to 

provide the needed spatial and temporal 

detail to more completely and 

accurately estimate the changes in 

ambient levels of these pollutants. As 

discussed in Section VII.D, timing and 

resource constraints precluded EPA 

from conducting a full-scale 

photochemical air quality modeling 

analysis in time for the NPRM. For the 

final rule, however, a national-scale air 

quality modeling analysis will be 

performed to analyze the impacts of the 

proposed standards on PM2.5, ozone, 

and selected air toxics (i.e., benzene, 

formaldehyde, acetaldehyde, ethanol, 

acrolein and 1,3-butadiene). As 

described in Section VII.D.2, EPA 

intends to use a 2005-based Community 

Multi-scale Air Quality (CMAQ) 

modeling platform as the tool for the air 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24919 

quality modeling. The CMAQ modeling 

system is a comprehensive threedimensional grid-based Eulerian air 

quality model designed to estimate the 

formation and fate of oxidant 

precursors, primary and secondary PM 

concentrations and deposition, and air 

toxics, over regional and urban spatial 

scales (e.g., over the contiguous U.S.). 

The lack of air quality modeling data 

also precluded EPA from conducting its 

standard analysis of human health 

impacts, where CMAQ output data are 

used as inputs to the Environmental 

Benefits Mapping and Analysis Program 

(BenMAP). Section IX.D of this 

preamble describes the human health 

impacts that will be quantified and 

monetized for the final rule, as well as 

the unquantified impacts that will be 

qualitatively described. 

4. Water 

As the production of biofuels 

increases to meet the requirements of 

this proposed rule, there may be adverse 

impacts on both water quality and 

quantity. Increased production of 

biofuels may lead to increased 

application of fertilizer and pesticides 

and increased soil erosion, which could 

impact water quality. Since ethanol 

production uses large quantities of 

water, the supply of water could also be 

significantly impacted in some 

locations. 

EPA focused the water quality 

analysis for this proposal on the impacts 

of corn produced for ethanol for several 

reasons. Corn has the highest fertilizer 

and pesticide use per acre and accounts 

for the largest share of nitrogen fertilizer 

use among all crops. Furthermore, cornbased ethanol is expected to be a large 

component of the biofuels mix. 

Fertilizer nutrients that are not used 

by the crops are available to runoff to 

surface water or leach into groundwater. 

Nutrient enrichment due to human 

activities is one of the leading problems 

facing our nation’s lakes, reservoirs, and 

estuaries, and also has negative impacts 

on aquatic life in streams; adverse 

health effects on humans and domestic 

animals; and impairs aesthetic and 

recreational use. Excess nutrients can 

lead to excessive growth of algae in 

rivers and streams, and aquatic plants in 

all waters. Nutrient pollution is 

widespread. The most widely known 

examples of significant nutrient impacts 

include the Gulf of Mexico and the 

Chesapeake Bay, however waterbodies 

in virtually every state and territory are 

impacted by nutrient-related 

degradation. A more detailed discussion 

of nutrient pollution can be found in 

Section X of this preamble and in 

Chapter 6 of the DRIA. 

To provide a quantitative estimate of 

the impact of this proposal and 

production of corn ethanol generally on 

water quality, EPA conducted an 

analysis that modeled the changes in 

loadings of nitrogen, phosphorus, and 

sediment from agricultural production 

in the Upper Mississippi River Basin 

(UMRB). The UMRB is representative of 

the many potential issues associated 

with ethanol production, including its 

connection to major water quality 

concerns such as Gulf of Mexico 

hypoxia, large corn acreage, and 

numerous ethanol production plants. 

The UMRB contributes 39% of nitrogen 

loads and 26% of phosphorus loads to 

the Gulf of Mexico. 

EPA selected the SWAT (Soil and 

Water Assessment Tool) model to assess 

nutrient loads from changes in 

agricultural production in the UMRB. 

SWAT is a physical process model 

developed to quantify the impact of 

land management practices in large, 

complex watersheds. In conducting its 

analysis EPA quantified the impacts 

from a baseline that preceded the 

current high production of ethanol from 

corn to four future years—2010, 2015, 

2020 and 2022. 

Table II.B.4–1 summarizes the model 

outputs at the outlet of the UMRB in the 

Mississippi River at Grafton, Illinois for 

each of the four scenario years. The 

local impact in smaller watersheds 

within the UMRB may be significantly 

different. The decreasing nitrogen load 

over time is likely attributed to the 

increased corn yield production, 

resulting in greater plant uptake of 

nitrogen. The relatively stable sediment 

loadings are likely due to the fact that 

corn was modeled assuming that corn 

stover is left on the fields following 

harvest. 

TABLE II.B.4–1—CHANGES FROM THE 2005 BASELINE TO THE MISSISSIPPI RIVER AT GRAFTON, ILLINOIS FROM THE

UPPER MISSISSIPPI RIVER BASIN

2005 Baseline 2010 2015 2020 2022 

Average corn yield (bushels/acre) ........................ 141 ........................................................................ 150 158 168 171 

Nitrogen ................................................................ 1433.5 million lbs ................................................. +5.5% +4.7% +2.5% +1.8% 

Phosphorus ........................................................... 132.4 million lbs ................................................... +2.8% +1.7% +0.98% +0.8% 

Sediment ............................................................... 6.4 million tons ..................................................... +0.5% +0.3% +0.2% +0.1% 

After evaluating comments on this 

proposal, if time and resources permit, 

EPA may conduct additional water 

quality analyses using the SWAT model 

in the UMRB. Potential future analyses 

could include: (1) Determination of the 

most sensitive assumptions in the 

model, (2) water quality impacts from 

the changes in ethanol volumes between 

the reference case and this proposal, (3) 

removing corn stover for cellulosic 

ethanol, and (4) a case study of a smaller 

watershed to evaluate local water 

quality impacts that are impossible to 

ascertain at the scale of the UMRB. 

EPA also qualitatively examined other 

water issues, which are also discussed 

in detail in Section X of this Preamble, 

and Chapter 6 of the DRIA. 

5. Agricultural Commodity Prices 

The recent increase in food prices, 

both domestically and internationally, 

has raised the issue of whether diverting 

grains and oilseeds for fuel production 

is having a large impact on commodity 

markets. While we share the concern 

that food prices have increased 

significantly over the same time period 

in which renewable fuel production has 

increased, many factors have 

contributed to recent increases in food 

prices. As described by the U.S. 

Department of Agriculture (USDA), the 

Department of Energy (DOE), the 

Council of Economic Advisors (CEA), 

and others, the recent increase in 

commodity prices has been influenced 

by factors as diverse as world economic 

growth, droughts in Australia, China 

and Eastern Europe, increasing oil 

prices, changes in investment strategies, 

and the declining value of the U.S. 

dollar. While the increase in renewable 

fuel production has contributed to the 

increase in commodity prices, the 

magnitude of the contribution of the 

RFS has most likely been minor, as 

market conditions have continued to 

push renewable fuel use beyond the 

mandated levels. 

As the mandated levels of renewable 

fuels continue to rise in the future, our 

24920 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

economic modeling suggests that the 

impact of the RFS2 program on food 

prices will continue to be modest, 

particularly with the expansion of 

cellulosic biofuels. Table II.B.5–1 

summarizes the changes in prices for 

some commodities we have estimated 

for this proposal. Further discussion can 

be found in Section IX.A. 

TABLE II.B.5–1—CHANGE IN U.S. 

COMMODITY PRICES FOR 2022 IN

COMPARISON TO THE REFERENCE

CASE

[2006$] 

Corn ........................ $0.15/bushel. 

Soybeans ................ $0.29/bushel. 

Sugarcane ............... $13.34/ton. 

Beef ......................... $0.93/hundred pounds. 

II. What Are the Major Elements of the 

Program Required Under EISA? 

While EISA made a number of 

changes to CAA section 211(o) that must 

be reflected in the RFS program 

regulations, it left many of the basic 

program elements intact, including the 

mechanism for translating national 

renewable fuel volume requirements 

into applicable standards for individual 

obligated parties, requirements for a 

credit trading program, geographic 

applicability, treatment of small 

refineries, and general waiver 

provisions. As a result, we propose that 

many of the regulatory requirements of 

the RFS1 program would remain largely 

or, in some cases, entirely unchanged. 

These provisions would include the 

distribution of RINs, separation of RINs, 

use of RINs to demonstrate compliance, 

provisions for exporters, recordkeeping 

and reporting, deficit carryovers, and 

the valid life of RINs. 

The primary elements of the RFS 

program that we propose changing to 

implement the requirements in EISA fall 

primarily into the following five areas: 

(1) Expansion of the applicable 

volumes of renewable fuel 

(2) Separation of the volume 

requirements into four separate 

categories of renewable fuel, with 

corresponding changes to the RIN and to 

the applicable standards 

(3) Changes to the definition of 

renewable fuels and criteria for 

determining which if any of the four 

renewable fuel categories a given 

renewable fuel is eligible to meet 

(4) Expansion of the fuels subject to 

the standards (and applicable to 

refiners, blenders, and importers of 

those fuels) to include diesel and certain 

nonroad fuels 

(5) Inclusion of specific types of 

waivers and EPA-generated credits for 

cellulosic biofuel. 

EISA does not change the basic 

requirement under CAA 211(o) that the 

RFS program include a credit trading 

program. In the May 1, 2007 final 

rulemaking implementing the RFS1 

program, we described how we 

reviewed a variety of approaches to 

program design in collaboration with 

various stakeholders. We finally settled 

on a RIN-based system for compliance 

and credit purposes as the one which 

met our goals of being straightforward, 

maximizing flexibility, ensuring that 

volumes are verifiable, and maintaining 

the existing system of fuel distribution 

and blending. RINs represent the basic 

framework for ensuring that the 

statutorily required volumes of 

renewable fuel are produced and used 

as transportation fuel in the U.S. The 

use of RINs is predicated on the fact that 

once renewable fuels are produced or 

imported, there is very high confidence 

that, setting aside exports, all but de 

minimus quantities will in fact be used 

as transportation fuel in the U.S. 

Focusing on production of renewable 

fuel as a surrogate for the later actual 

blending and use of such fuel has many 

benefits as far as streamlining the RFS 

program and minimizing the impact that 

the program has on the business 

operations of the regulated industries. 

Since the RIN-based system generally 

has been successful in meeting EPA’s 

goals, we propose to maintain much of 

its structure under RFS2. 

This section describes the regulatory 

changes we propose to implement the 

new EISA provisions. Section IV 

describes other changes to the RFS 

program that we have considered or are 

proposing, including a concept for an 

EPA-moderated RIN trading system that 

would provide a context within which 

all RIN transfers could occur. 

A. Changes to Renewable Identification 

Numbers (RINs) 

Under RFS2, we propose that each 

RIN would continue to represent one 

gallon of renewable fuel for compliance 

purposes consistent with our approach 

under RFS1, and the RIN would 

continue to have 38 digits. In general 

the codes within the RIN would have 

the same meaning under RFS2 as they 

do under RFS1, with the exception of 

the D code which would be expanded 

to cover the four categories of renewable 

fuel defined in EISA. The proposed 

change to the D code is described in 

Table III.A–1. 

TABLE III.A–1—PROPOSED CHANGE TO D CODE

D value Meaning under RFS1 Meaning under RFS2 

1 ............................................................ Cellulosic biomass ethanol ................................................................................. Cellulosic biofuel. 

2 ............................................................ Any renewable fuel that is not cellulosic biomass ethanol ................................ Biomass-based diesel. 

3 ............................................................ Not applicable ..................................................................................................... Advanced biofuel. 

4 ............................................................ Not applicable ..................................................................................................... Renewable fuel. 

The determination of which D code 

would be assigned to a given batch of 

renewable fuel is described in more 

detail in Section III.D.2 below. 

As described in Section II.A.5, we are 

proposing that the RFS2 program go into 

effect on January 1, 2010. However, we 

are also taking comment on other 

potential start dates including January 1, 

2011 and dates between January 1, 2010 

and January 1, 2011. If we were to start 

the RFS2 program during 2010 but after 

January 1, some 2010 RINs would be 

generated under the RFS1 requirements 

and others would be generated under 

the RFS2 requirements, but all RINs 

generated in 2010 would need to be 

valid for meeting the appropriate 2010 

annual standards. Since RFS1 RINs and 

RFS2 RINs would differ in the meaning 

of the D codes, we would need a 

mechanism for distinguishing between 

these two categories of RINs in order to 

appropriately apply them to the 

standards. One straightforward way of 

accomplishing this would be to use 

values for the D code under RFS2 that 

do not overlap the values for the D code 

under RFS1. Table III.A–2 describes the 

D code definitions under such an 

alternative approach. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24921 

TABLE III.A–2—ALTERNATIVE D CODE DEFINITIONS

D value Meaning under RFS1 Meaning under RFS2 

1 ............................................................ Cellulosic biomass ethanol ................................................................................. Not applicable. 

2 ............................................................ Any renewable fuel that is not cellulosic biomass ethanol ................................ Not applicable. 

3 ............................................................ Not applicable ..................................................................................................... Cellulosic biofuel. 

4 ............................................................ Not applicable ..................................................................................................... Biomass-based diesel. 

5 ............................................................ Not applicable ..................................................................................................... Advanced biofuel. 

6 ............................................................ Not applicable ..................................................................................................... Renewable fuel. 

In this alternative approach, D code 

values of 1 and 2 would only be relevant 

for RINs generated under RFS1, and D 

code values of 3, 4, 5, and 6 would only 

be relevant for RINs generated under 

RFS2. As a result, 2010 RINs generated 

under RFS1 would be subject to our 

proposed RFS1/RFS2 transition 

provisions wherein they would be 

assigned to one of the four annual 

standards that would apply in 2010 

using their RR and/or D codes. See 

Section III.G.3 for further description of 

how we propose using RFS1 RINs to 

meet standards under RFS2. 

Under RFS2, each batch-RIN 

generated would continue to uniquely 

identify not only a specific batch of 

renewable fuel, but also every gallonRIN assigned to that batch. Thus the RIN 

would continue to be defined as 

follows: 

RIN: KYYYYCCCCFFFFFBBBBBR

RDSSSSSSSSEEEEEEEE 

Where: 

K = Code distinguishing assigned RINs from 

separated RINs 

YYYY = Calendar year of production or 

import 

CCCC = Company ID 

FFFFF = Facility ID 

BBBBB = Batch number 

RR = Code identifying the Equivalence Value 

D = Code identifying the renewable fuel 

category 

SSSSSSSS = Start of RIN block 

EEEEEEEE = End of RIN block 

B. New Eligibility Requirements for 

Renewable Fuels 

Aside from the higher volume 

requirements, most of the substantive 

changes that EISA makes to the RFS 

program affect the eligibility of 

renewable fuels in meeting one of the 

four volume requirements. Eligibility 

would be determined based on the types 

of feedstocks that can be used, the land 

that can be used to grow feedstocks for 

renewable fuel production, the 

processes that can be used to convert 

those feedstocks into fuel, and the 

lifecycle greenhouse gas (GHG) 

emissions that can be emitted in 

comparison to the gasoline or diesel that 

the renewable fuel displaces. This 

section describes these eligibility 

criteria and how we propose to include 

them in the RFS2 program. 

1. Changes in Renewable Fuel 

Definitions 

Under the existing Renewable Fuel 

Standard (RFS1), renewable fuel is 

defined generally as ‘‘any motor vehicle 

fuel that is used to replace or reduce the 

quantity of fossil fuel present in a fuel 

mixture used to fuel a motor vehicle’’. 

The RFS1 definition includes motor 

vehicle fuels produced from biomass 

material such as grain, starch, fats, 

greases, oils, and biogas. The definition 

specifically includes cellulosic biomass 

ethanol, waste derived ethanol, and 

biodiesel, all of which are defined 

separately. (See 72 FR 23915.) 

The definitions of renewable fuels 

under today’s proposed rule (RFS2) are 

based on the new statutory definition in 

EISA. Like the existing rules, the 

definitions in RFS2 include a general 

definition of renewable fuel, but unlike 

RFS1, we are including a separate 

definition of ‘‘Renewable Biomass’’ 

which identifies the feedstocks from 

which renewable fuels may be made. 

Another difference in the definitions 

of renewable fuel is that RFS2 contains 

three subcategories of renewable fuels: 

(1) Advanced Biofuel, (2) Cellulosic 

Biofuel and (3) Biomass-Based Diesel. 

Each must meet threshold levels of 

reduction of greenhouse gas emissions 

as discussed in Section III.B.2. The 

specific definitions and how they differ 

from RFS1 follow below. 

a. Renewable Fuel and Renewable 

Biomass 

‘‘Renewable Fuel’’ is defined as fuel 

produced from renewable biomass and 

that is used to replace or reduce the 

quantity of fossil fuel present in a 

transportation fuel. The definition of 

‘‘Renewable Fuel’’ now refers to 

‘‘transportation fuel’’ rather than 

referring to motor vehicle fuel. 

‘‘Transportation fuel’’ is also defined, 

and means fuel used in motor vehicles, 

motor vehicle engines, nonroad vehicles 

or nonroad engines (except for ocean 

going vessels). 

We propose to allow fuel producers 

and importers to include electricity, 

natural gas, and propane (i.e., 

compressed natural gas (CNG) and 

liquefied petroleum gas (LPG)) as a RINgenerating renewable fuel in today’s 

program only if they can identify the 

specific quantities of their product 

which are actually used as a 

transportation fuel, and if the fuel is 

produced from renewable biomass. This 

may be possible for some portion of 

electricity, natural gas, and propane 

since many of the affected vehicles and 

equipment are in centrally-fueled fleets 

supplied under contract by a particular 

producer or importer of natural gas or 

propane. A producer or importer of 

electricity, natural gas, or propane who 

could document the use of his product 

in a vehicle or engine would be allowed 

to generate RINs to represent that 

product, if it met the definition of 

renewable fuel. Given that the primary 

use of electricity, natural gas, and 

propane is not for fueling vehicles and 

engines, and the producer generally 

does not know how it will be used, we 

cannot require that producers or 

importers of these fuels generate RINs 

for all the volumes they produce as we 

do with other renewable fuels. 

Our proposal to allow electricity, 

natural gas, and propane to generate 

RINs under certain conditions is 

consistent with our treatment of neat 

renewable fuels under RFS1 and EISA’s 

requirement that all transportation fuels 

be included in RFS2. With specific 

regard to renewable electricity, Section 

206 of EISA requires the EPA to conduct 

a study of the feasibility of issuing 

credits under the RFS2 program for 

renewable electricity used by electric 

vehicles. Once completed, this study 

will provide additional information 

regarding the means by which 

renewable electricity is able to generate 

RINs under the RFS2 program. 

As an alternative to allowing 

producers and importers of electricity, 

natural gas, and propane to generate 

RINs if they can demonstrate that their 

product is a renewable fuel and it is 

used as transportation fuel, we could 

allow or require parties who supply 

these fuels to centrally fueled fleets to 

generate the RINs even if they are not 

the producer of the fuel. This approach 

24922 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

5Construction and demolition (C&D) wastes are 

not typically considered as elements of MSW. 

Because they are significant feedstocks for the 

production of ethanol, we include such wastes in 

our economic analysis (Section V). Therefore, for all 

practical purposes, the discussion here as it 

pertains to whether MSW should be included in the 

definition of ‘‘renewable biomass’’ also applies to 

C&D wastes. 

would treat the supplier of the fuel to 

the fleet as the producer or importer 

who then generates RINs, as they are the 

party who in effect changes the fuel 

from a fuel that can be used in a variety 

of ways and ensures that it is in fact 

used as transportation fuel. This 

alternative approach might enable a 

larger volume of electricity, natural gas, 

and propane that is made from 

renewable biomass and which is 

actually used in vehicles or engines to 

be included in our proposed fuels 

program as RIN-generating, since in 

many cases a supplier could document 

the use of these fuels in vehicles or 

engines, while a producer could not. In 

addition, in this case the supplier is the 

party who causes the fuel to transition 

from general fuel supply to fuel 

designated for use in motor vehicles or 

nonroad applications—in that sense, the 

supplier is more like a producer or 

importer than the upstream producer or 

importer. However, if we were to allow 

the supplier of renewable electricity, 

natural gas, or propane to generate RINs 

in such cases, it may also be appropriate 

to require suppliers of fossil-based 

electricity, natural gas, or propane to 

determine a Renewable Volume 

Obligation (RVO) that includes these 

fuels used as transportation fuel. See 

Section III.F.3 for further discussion. We 

request comment on this alternative 

approach for generating RINs for 

renewable electricity, natural gas and 

propane. 

The term ‘‘Renewable Biomass’’ as 

defined in EISA, means: 

1. Planted crops and crop residue, 

2. Planted trees and tree residues, 

3. Animal waste material and 

byproducts, 

4. Slash and pre-commercial 

thinnings (from non-federal forestlands), 

5. Biomass cleared from the vicinity 

of buildings and other areas to reduce 

the risk of wildfire, 

6. Algae, and 

7. Separated yard waste or food waste. 

Section III.B.4 of this preamble 

outlines our proposed interpretations 

for most of the key terms contained in 

the EISA definition of ‘‘renewable 

biomass’’ and possible approaches for 

implementing the land restrictions on 

renewable biomass that are included in 

EISA. It is worth noting here, however, 

that the statutory definition of 

‘‘renewable biomass’’ does not include a 

reference to municipal solid waste 

(MSW) as did the definition of 

‘‘cellulosic biomass ethanol’’ in the 

Energy Policy Act of 2005 (EPAct), but 

instead includes ‘‘separated yard waste 

and food waste. EPA’s proposed 

definition of renewable biomass in 

today’s regulation includes the language 

present in EISA, and we propose to 

clarify in the regulations that ‘‘yard 

waste’’ is leaves, sticks, pine needles, 

grass and hedge clippings, and similar 

waste from residential, commercial, or 

industrial areas. Nevertheless, EPA 

invites comment on whether the 

definition of ‘‘renewable biomass’’ 

should be interpreted as including or 

excluding MSW from the definition of 

renewable biomass. 

While the lack of a reference to MSW 

and the new listing of separated yard 

waste and food waste could be readily 

interpreted to exclude MSW as a 

qualifying feedstock under RFS2, EPA 

believes there are indications of 

ambiguity on this issue and solicits 

comment on whether EPA can and 

should interpret EISA as including 

MSW that contains yard and/or food 

waste within the definition of renewable 

biomass. On the one hand, the reference 

in the statutory definition to ‘‘separated 

yard waste and food waste,’’ and the 

lack of reference to other components of 

MSW (such as waste paper and wood 

waste) suggests that only yard and food 

wastes physically separated from other 

waste materials satisfy the definition of 

renewable biomass as opposed to the 

yard and food waste present in MSW. 

This view would exclude unprocessed 

MSW from any role in the development 

of renewable fuel under EISA, and 

would also likely severely limit the 

amount of yard and food waste available 

as feedstock for EISA-qualifying fuel, 

since large quantities of these materials 

are disposed of as unprocessed MSW. 

On the other hand, there are some 

indications that Congress may not have 

specifically intended to exclude MSW 

from playing a role in the development 

of renewable fuels under EISA. For 

example, ethanol ‘‘derived from waste 

material’’ and biogas ‘‘including landfill 

gas’’ are specifically identified as 

‘‘eligible for consideration’’ in the 

definition of advanced biofuel. While 

landfill gas is generated primarily by the 

yard waste and food waste in a landfill, 

these wastes typically are not separated 

from each other in a landfill. In 

addition, Congress did not define the 

term ‘‘separated’’ and did not otherwise 

specify the degree of ‘‘separation’’ 

required of yard and food waste in the 

definition of renewable biomass. Thus, 

it might be reasonable to consider these 

items sufficiently ‘‘separated’’ from 

other materials, including non-waste 

materials, when food and yard waste is 

present in MSW. In addition, the 

processing of MSW to fuel will 

effectively separate out the materials in 

MSW that cannot be made into fuel, 

such as glass and metal, and nonbiomass portions of MSW (for example, 

pastics) could be excluded from getting 

credit under the RFS program as 

described in Section III.D.4. EPA invites 

comment on whether there is enough 

separation of food and yard waste in 

MSW used in renewable fuel production 

for MSW containing yard and food 

waste to meet the definition of 

renewable biomass. 

Approximately 35% by weight of 

MSW is paper wastes, and another 6% 

by weight from wood wastes. Combined 

with food and yard wastes, more than 

60% by weight of MSW is biomass that 

could be used to make ethanol and other 

renewable fuels.5 The volume of ethanol 

associated with MSW as a feedstock is 

described in more detail in Section 1.1 

of the Draft Regulatory Impact Analysis 

(DRIA). 

Our discussions with stakeholders 

indicate that a potential concern with 

interpreting the definition of renewable 

biomass to include MSW containing 

yard and/or food waste is that this 

approach may cause some decrease in 

the amount of paper that is separated 

from the MSW waste stream and 

recycled into paper products. We 

believe, however, that current waste 

handling practices and current and 

anticipated market conditions would 

continue to provide a strong incentive 

for paper separation and recycling. A 

narrow reading of the statute to exclude 

MSW-derived renewable fuel would 

directionally reduce the options 

available for meeting the goal of EISA to 

reduce our dependence on foreign 

sources of energy. 

By including MSW containing yard 

and/or food waste in the definition of 

renewable biomass, we could also allow 

renewable fuel to be produced in part 

from certain plastics in the MSW waste 

stream. We believe this could be 

appropriate given that plastics that 

would otherwise be destined for 

landfills can be used for fuel and energy 

production. We recognize that the 

definition of renewable biomass 

generally includes only materials of a 

non fossil-fuel origin, and ask that 

commenters consider this issue in their 

comments on whether: (1) MSW 

containing yard and food waste should 

qualify as renewable biomass, (2) if nonfossil portions of MSW should be 

included in the definition of renewable 

biomass, and (3) if non-fossil portions of 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24923 

6The production of biodiesel (mono alkyl esters) 

does require the addition of methanol which is 

usually derived from natural gas, but which 

contributes a very small amount to the resulting 

product. We do not believe that this was intended 

by the statute’s reference to ‘‘co-processing’’ which 

we believe was intended to address only renewable 

fats or oils co-processed with petroleum in a 

hydrotreater to produce renewable diesel. 

MSW should not be included, whether 

the approach discussed in Section 

III.D.4 can provide an appropriate 

means for excluding the non-fossil 

portions. 

Although we are proposing to exclude 

MSW from the definition of ‘‘renewable 

biomass’’ for the proposed rule, our 

analysis of renewable fuel volume 

(discussed in Section V) assumes that 

MSW is included for purposes of 

quantifying the potential future volume 

of renewable fuel. EPA intends to 

resolve this matter in the final rule, and 

we solicit comment on the approach 

that we should take. 

b. Advanced Biofuel 

‘‘Advanced Biofuel’’ is a renewable 

fuel other than ethanol derived from 

corn starch and which must also 

achieve a lifecycle GHG emission 

displacement of 50%, compared to the 

gasoline or diesel fuel it displaces. As 

such, advanced biofuel would be 

assigned a D code of 3 as shown in 

Table III.A–1. 

‘‘Advanced biofuel’’ also may be 

biomass-based diesel, biogas (including 

landfill gas and sewage waste treatment 

gas), butanol or other alcohols produced 

through conversion of organic matter 

from renewable biomass, and other fuels 

derived from cellulosic biomass, as long 

as it meets the proposed 40–44% GHG 

emission reduction threshold. 

‘‘Advanced Biofuel’’ is a renewable fuel 

other than ethanol derived from corn 

starch and for which lifecycle GHG 

emissions are at least 40–44% less than 

the gasoline or diesel fuel it displaces. 

Advanced biofuel would be assigned a 

D code of 3 as shown in Table III.A–1. 

While ‘‘Advanced Biofuel’’ 

specifically excludes ethanol derived 

from corn starch, it includes other types 

of ethanol derived from renewable 

biomass, including ethanol made from 

cellulose, hemicellulose, lignin, sugar or 

any starch other than corn starch, as 

long as it meets the proposed 40–44% 

GHG emission reduction threshold. 

Thus, even if corn starch-derived 

ethanol were made so that it met the 

proposed 40–44% GHG reduction 

threshold, it would still be excluded 

from being defined as an advanced 

biofuel. Such ethanol, while not an 

advanced biofuel, would still qualify as 

a renewable fuel for purposes of meeting 

the standards. 

‘‘Advanced biofuel’’ also may be 

biomass-based diesel, biogas (including 

landfill gas and sewage waste treatment 

gas), butanol or other alcohols produced 

through conversion of organic matter 

from renewable biomass, and other fuels 

derived from cellulosic biomass, as long 

as it is derived from renewable biomass 

and meets the proposed 40–44% GHG 

emission reduction threshold. 

c. Cellulosic Biofuel 

Cellulosic biofuel is renewable fuel, 

not necessarily ethanol, derived from 

any cellulose, hemicellulose, or lignin 

each of which must originate from 

renewable biomass. It must also achieve 

a lifecycle GHG emission reduction of at 

least 60%, compared to the gasoline or 

diesel fuel it displaces. Cellulosic 

biofuel is assigned a D code of 1 as 

shown in Table III.A–1. Cellulosic 

biofuel in general also qualifies as both 

‘‘advanced biofuel’’ and ‘‘renewable 

fuel’’. 

The proposed definition of cellulosic 

biofuel for RFS2 is broader in some 

respects than the RFS1 definition of 

‘‘cellulosic biomass ethanol’’. That 

definition included only ethanol, 

whereas the RFS2 definition of 

cellulosic biofuels includes any 

biomass-to-liquid fuel in addition to 

ethanol. The definition of ‘‘cellulosic 

biofuel’’ in RFS2 differs from RFS1 in 

another significant way. The RFS1 

definition provided that ethanol made at 

any facility—regardless of whether 

cellulosic feedstock is used or not—may 

be defined as cellulosic if at such 

facility ‘‘animal wastes or other waste 

materials are digested or otherwise used 

to displace 90% or more of the fossil 

fuel normally used in the production of 

ethanol.’’ This provision was not 

included in EISA, and therefore does 

not appear in the definitions pertaining 

to cellulosic biofuel in today’s proposed 

rule. 

d. Biomass-Based Diesel 

Under today’s proposed rule 

‘‘Biomass-based diesel’’ includes both 

biodiesel (mono-alkyl esters) and nonester renewable diesel (including 

cellulosic diesel). The definition is the 

same very broad definition of 

‘‘biodiesel’’ that was in EPAct and in 

RFS1, with three exceptions. First, EISA 

requires that such fuel be made from 

renewable biomass. Second, its lifecycle 

GHG emissions must be at least 50% 

less than the gasoline or diesel fuel it 

displaces. Third, the statutory definition 

of ‘‘Biomass-based diesel’’ excludes 

renewable fuel derived from coprocessing biomass with a petroleum 

feedstock. In drafting the proposed 

definition, we considered two options 

for how co-processing could be treated. 

The first option would consider coprocessing to occur only if both 

petroleum and biomass feedstock are 

processed in the same unit 

simultaneously. The second option 

would consider co-processing to occur if 

renewable biomass and petroleum 

feedstock are processed in the same unit 

at any time; i.e., either simultaneously 

or sequentially. Under the second 

option, if petroleum feedstock was 

processed in the unit, then no fuel 

produced from such unit, even from a 

biomass feedstock, would be deemed to 

be biomass-based diesel. 

We are proposing the first option to be 

used in the definition in today’s rule. 

Under this approach, a batch of fuel 

qualifying for the D code of 2 that is 

produced in a processing unit in which 

only renewable biomass is the feedstock 

for such batch, would meet the 

definition of ‘‘Biomass-Based Diesel. 

Thus, serial batch processing in which 

100% vegetable oil is processed one 

day/week/month and 100% petroleum 

the next day/week/month could occur 

without the activity being considered 

‘‘co-processing.’’ The resulting products 

could be blended together, but only the 

volume produced from vegetable oil 

would count as biomass-based diesel. 

We believe this is the most 

straightforward approach and an 

appropriate one, given that it would 

allow RINs to be generated for volumes 

of fuel meeting the 50% GHG reduction 

threshold that is derived from 

renewable biomass, while not providing 

any credit for fuel derived from 

petroleum sources. In addition, this 

approach avoids the need for potentially 

complex provisions addressing how fuel 

should be treated when existing or even 

mothballed petroleum hydrotreating 

equipment is retrofitted and placed into 

new service for renewable fuel 

production or vice versa. 

Under today’s proposal, any fuel that 

does not satisfy the definition of 

biomass-based diesel only because it is 

co-processed with petroleum would still 

meet the definition of ‘‘Advanced 

Biofuel’’ provided it meets the 50% 

GHG threshold and other criteria for the 

D code of 3. Similarly it would meet the 

definition of renewable fuel if it meets 

a GHG emission reduction threshold of 

20%. In neither case, however, would it 

meet the definition of biomass-based 

diesel. 

This restriction is only really an issue 

for renewable diesel and biodiesel 

produced via the fatty acid methyl ester 

(FAME) process. For other forms of 

biodiesel, it is never made through any 

sort of co-processing with petroleum.6

24924 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

7Section 211(o)(2)(A)(i) of the Clean Air Act as 

amended by EISA. Note that this is not a 

prohibition—facilities that make ethanol can 

continue to do so. It is a minimum requirement for 

facilities to generate RINs under today’s proposed 

rule; failure to meet such requirements means that 

the ethanol produced from such facilities cannot 

generate RINs. 

Producers of renewable diesel must 

therefore specify whether or not they 

use ‘‘co-processing’’ to produce the fuel 

in order to determine the correct D code 

for the RIN. 

e. Additional Renewable Fuel 

The statutory definition of ‘‘additional 

renewable fuel’’ specifies fuel produced 

from renewable biomass that is used to 

replace or reduce fossil fuels used in 

home heating oil or jet fuel. EISA 

indicates that EPA may allow for the 

generation of credits for such additional 

renewable fuel that will be valid for 

compliance purposes. Under the RFS 

program, RINs operate in the role of 

credits, and RINs are generated when 

renewable fuel is produced rather than 

when it is blended. In most cases, 

however, renewable fuel producers do 

not know at the time of fuel production 

(and RIN generation) how their fuel will 

ultimately be used. 

Under RFS1, only RINs assigned to 

renewable fuel that was blended into 

motor vehicle fuel are valid for 

compliance purposes. As a result, we 

created special provisions requiring that 

RINs be retired if they were assigned to 

renewable fuel that was ultimately 

blended into nonroad fuel. The new 

EISA provisions regarding additional 

renewable fuel make the RFS1 

requirement for retiring RINs 

unnecessary if renewable fuel is 

blended into heating oil or jet fuel. As 

a result, we propose modifying the 

regulatory requirements to allow RINs 

assigned to renewable fuel blended into 

heating oil or jet fuel to continue to be 

valid for compliance purposes. 

2. Lifecycle GHG Thresholds 

As part of the new definitions that 

EISA creates for cellulosic biofuel, 

biomass-based diesel, advanced biofuel, 

and renewable fuel, EISA also sets 

minimum performance measures or 

‘‘thresholds’’ for lifecycle GHG 

emissions. These thresholds represent 

the percent reduction in lifecycle GHGs 

that is estimated to occur when a 

renewable fuel displaces gasoline or 

diesel fuel. Table III.B.2–1 lists the 

thresholds required by EISA. 

TABLE III.B.2–1—REQUIRED

LIFECYCLE GHG THRESHOLDS

[Percent reduction from a 2005 gasoline or 

diesel baseline] 

Renewable fuel ................................. 20 

Advanced biofuel .............................. 50 

Biomass-based diesel ...................... 50 

Cellulosic biofuel ............................... 60 

There are also special provisions for 

each of these thresholds: 

Renewable fuel: The 20% threshold 

only applies to renewable fuel from new 

facilities that commenced construction 

after December 19, 2007, with an 

additional exemption from the 20% 

threshold for ethanol plants that 

commenced construction in 2008 or 

2009 and are fired with natural gas, 

biomass, or any combination thereof. 

Facilities not subject to the 20% 

threshold would be ‘‘grandfathered.’’ 

See Section III.B.3 below for a complete 

discussion of grandfathering. Also, EPA 

can adjust the 20% threshold to as low 

as 10%, but the adjustment must be the 

minimum possible, and the resulting 

threshold must be established at the 

maximum achievable level based on 

natural gas fired corn-based ethanol 

plants. 

Advanced biofuel and biomass-based 

diesel: The 50% threshold can be 

adjusted to as low as 40%, but the 

adjustment must be the minimum 

possible and result in the maximum 

achievable threshold taking cost into 

consideration. Also, such adjustments 

could be made only if it was determined 

that the 50% threshold was not 

commercially feasible for fuels made 

using a variety of feedstocks, 

technologies, and processes. As 

described more fully in Section VI.D, we 

are proposing that the GHG threshold 

for advanced biofuels be adjusted to 

44% or potentially as low as 40% 

depending on the results from the 

analyses that will be conducted for the 

final rule. 

Cellulosic biofuel: Similarly to 

advanced biofuel and biomass-based 

diesel, the 60% threshold applicable to 

cellulosic biofuel can be adjusted to as 

low as 50%, but the adjustment must be 

the minimum possible and result in the 

maximum achievable threshold taking 

cost into consideration. Also, such 

adjustments could be made only if it 

was determined that the 60% threshold 

was not commercially feasible for fuels 

made using a variety of feedstocks, 

technologies, and processes. 

Our analyses of lifecycle GHG 

emissions, discussed in detail in Section 

VI, included all GHGs related to the full 

fuel cycle, including all stages of fuel 

and feedstock production and 

distribution, from feedstock generation 

and extraction through distribution, 

delivery, and use of the finished fuel. 

They included direct emissions and any 

significant indirect emissions such as 

significant emissions from land use 

changes. These lifecycle analyses were 

used to determine whether the 

thresholds shown in Table III.B.2–1 

should be adjusted downwards and 

which specific combinations of 

feedstock, fuel type, and production 

process met those thresholds under the 

assumption of a 100-year timeframe and 

2% discount rate for GHG emission 

impacts. 

We are not proposing to adjust any of 

these thresholds. However, we may 

adjust the GHG threshold for biomassbased diesel and/or advanced biofuel 

downward for the final rule based on 

additional lifecycle GHG analyses and 

further assessments of the market 

potential for volumes that can meet the 

requirements for these categories of 

renewable fuel. As explained in more 

detail in Section VI.D, ethanol produced 

from sugarcane sugar has been 

estimated to have a lifecycle GHG 

performance of 44% (under the 

assumption of a 100 year timeframe and 

2% discount rate), short of the 50% 

threshold specified in EISA. Ethanol 

from sugarcane is one of the few 

currently commercial pathways that 

have the potential to meet the 

requirements for advanced biofuel in 

the near term (in addition to cellulosic 

biofuel and biomass-based diesel which 

are a subset of advanced biofuel, and 

any other new fuels that may arise), and 

the only such pathway that was 

subjected to lifecycle analysis to date. If 

ethanol from sugarcane does not qualify 

as advanced biofuel, it is likely that it 

would not be commercially feasible for 

the advanced biofuel volume 

requirements to be met in the near term. 

We request comment on whether it 

would be necessary to adjust the GHG 

threshold for advanced biofuel. For 

similar reasons, as discussed in more 

detail in Section VI.D, we are also 

seeking comment on the need to adjust 

the GHG threshold for biomass-based 

diesel. 

3. Renewable Fuel Exempt From 20 

Percent GHG Threshold 

EISA amends section 211(o) of the 

Clean Air Act to provide that renewable 

fuel produced from new facilities which 

commenced construction after 

December 19, 2007 must achieve at least 

a 20% reduction in lifecycle greenhouse 

gas emissions compared to baseline 

lifecycle greenhouse gas emissions.7

Facilities that commenced construction 

before December 19, 2007 are 

‘‘grandfathered’’ and thereby exempt 

from the 20% GHG reduction 

requirement. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24925 

8The grandfathering and deemed compliant 

provisions in EISA sections 202 and 210 do not 

apply to the advanced biofuels, biomass-based 

diesel or cellulosic biofuel standards for which the 

Act requires a 50 or 60% GHG reduction threshold 

to be met regardless of when the facilities 

producing such fuels are constructed. 

For facilities that produce ethanol and 

for which construction commenced after 

December 19, 2007, section 210 of EISA 

states that ‘‘for calendar years 2008 and 

2009, any ethanol plant that is fired 

with natural gas, biomass, or any 

combination thereof is deemed to be in 

compliance with the 20% threshold.’’ 

We refer to these facilities as ‘‘deemed 

compliant.’’ This provision does not 

specify whether such facilities are 

deemed to be in compliance only for the 

period of 2008 and 2009, or indefinitely. 

Nor does EISA specify a date by which 

such qualifying facilities must have 

started operation. Although the Act is 

unclear as to whether their special 

treatment is only for 2008/2009, or for 

a longer time period, we believe that it 

would be a harsh result for investors in 

these new facilities, and generally 

inconsistent with the energy 

independence goals of EISA, for these 

new facilities to only be guaranteed two 

years of participation in the RFS2 

program. We propose that the statute be 

interpreted to mean that fuel from such 

qualifying facilities, regardless of date of 

startup of operations, would be exempt 

from the 20% GHG threshold 

requirement for the same time period as 

facilities that commence construction 

prior to December 19, 2007, provided 

that such plants commence construction 

prior to December 31, 2009, complete 

such construction in a reasonable 

amount of time, and continue to burn 

only natural gas, biomass, or a 

combination thereof. Therefore, we 

believe that they should be treated like 

grandfathered facilities. We seek 

comment, however, on the alternative in 

which after 2009, such plants must meet 

the 20% threshold in order to generate 

RINs for renewable fuel produced. 

Based on our survey of ethanol plants 

in operation, as well as those not yet in 

operation but which commenced 

construction prior to December 19, 

2007, it is likely that production 

capacity of ethanol from all such 

facilities will reach 15 billion gallons. 

(See Section 1.5.1.4 of the DRIA.) This 

volume of ethanol will be excluded 

from having to meet the 20% GHG 

threshold by the grandfathering and 

deemed compliant provisions of EISA.8

For ease of reference, we will refer to 

both these provisions as the ‘‘exemption 

provisions’’ of EISA. 

EISA does not define the term ‘‘new 

facility’’ and, as mentioned above, does 

not clarify whether ‘‘deemed 

compliant’’ facilities have that status for 

only 2008 and 2009, or for a longer time 

period. EPA seeks, in interpreting these 

terms, to avoid long-term backsliding 

with respect to environmental 

performance and to also provide a level 

playing field for future investments. 

Thus, we want to avoid incentives that 

would allow overall GHG performance 

to worsen via expansion at older plants 

with poorer GHG performance or by 

modifications such as switches to more 

polluting process heat sources, such as 

coal. At the same time, we also want to 

offer protection for historical business 

investments that were made prior to 

enactment of EISA, and we want future 

significant investments to meet the GHG 

reduction standards of the Act. Finally 

we want to avoid excessive case-by-case 

decision making where possible, and 

seek instead a rule that offers ease of 

implementation while providing 

certainty to EPA and the regulated 

industry. 

We are proposing one basic approach 

to the exemption provisions and seeking 

comment on five additional options. In 

fashioning the basic proposal and 

alternative options for exempted 

facilities, we considered aspects of 

exemption approaches elsewhere in the 

CAA and EPA regulations to evaluate 

whether they would foster the abovedescribed objectives. We are only 

looking to these other provisions for 

guidance and are not bound to follow 

any already-established approach for a 

different statutory provision (especially 

as those other provisions may contain 

definitions that Congress did not 

incorporate here). 

a. Definition of Commence Construction 

In defining ‘‘commence’’ and 

‘‘construction’’, we wanted a clear 

designation that would be broad enough 

to avoid facility-specific issues, but 

narrow enough to prevent new facilities 

(i.e., post-December 19, 2007) from 

being grandfathered. We believe that the 

definitions of ‘‘commence’’ and ‘‘Begin 

actual construction’’ in the Prevention 

of Significant Deterioration (PSD) 

regulations, which draws upon 

definitions in the Clean Air Act, served 

this purpose. (40 CFR 52.21(b)(9) and 

(11)). Specifically, under the PSD 

regulations, ‘‘commence’’ means that 

the owner or operator has all necessary 

preconstruction approvals or permits 

and either has begun a continuous 

program of actual on-site construction to 

be completed in a reasonable time, or 

entered into binding agreements which 

cannot be cancelled or modified without 

substantial loss.’’ Such activities 

include, but are not limited to, 

‘‘installation of building supports and 

foundations, laying underground pipe 

work and construction of permanent 

storage structures.’’ We have added 

language to the definition that is 

currently not in the PSD definition with 

respect to multi-phased projects. We are 

proposing that for multi-phased 

projects, commencement of construction 

of one phase does not constitute 

commencement of construction of any 

later phase, unless each phase is 

‘‘mutually dependent’’ on the other on 

a physical and chemical basis, rather 

than economic. 

The PSD regulations provide 

additional conditions beyond what 

constitutes commencement. 

Specifically, the regulations require that 

the owner or operator ‘‘did not 

discontinue construction for a period of 

18 months or more and completed 

construction within a reasonable time.’’ 

(40 CFR 52.21(i)(4)(ii)(c). While 

‘‘reasonable time’’ may vary depending 

on the type of project, we believe that 

with respect to renewable fuel facilities, 

a reasonable time to complete 

construction is no greater than 3 years 

from initial commencement of 

construction. We seek comment on the 

use of these definitions. 

b. Definition and Boundaries of a 

Facility 

We propose that the grandfathering 

and deemed compliant exemptions 

apply to ‘‘facilities.’’ Our proposed 

definition of this term is similar in some 

respects to the definition of ‘‘building, 

structure, facility, or installation’’ 

contained in the PSD regulations in 40 

CFR 52.21. We have modified the 

definition, however, to focus on the 

typical renewable fuel plant. We 

therefore propose to describe the 

exempt ‘‘facilities’’ as including all of 

the activities and equipment associated 

with the manufacture of renewable fuel 

which are located on one property and 

under the control of the same person or 

persons. 

c. Options Proposed in Today’s 

Rulemaking 

We are proposing one basic approach 

to the grandfathering provisions and 

seeking comment on five additional 

options. The basic approach would 

provide an indefinite extension of 

grandfathering and deemed compliant 

status but with a limitation of the 

exemption from the 20% GHG threshold 

to a baseline volume of renewable fuel. 

The five additional options for which 

we seek comment are: (1) Expiration of 

exemption for grandfathered and 

‘‘deemed compliant’’ status when 

facilities undergo sufficient changes to 

24926 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

be considered ‘‘reconstructed’’; (2) 

Expiration of exemption 15 years after 

EISA enactment, industry-wide; (3) 

Expiration of exemption 15 years after 

EISA enactment with limitation of 

exemption to baseline volume; (4) 

‘‘Significant’’ production components 

are treated as facilities and 

grandfathered or deemed compliant 

status ends when they are replaced; and 

(5) Indefinite exemption and no 

limitations placed on baseline volumes. 

i. Basic Approach: Grandfathering 

Limited to Baseline Volumes 

We are proposing and seeking 

comments on an option which generally 

limits the volume of any renewable fuel 

for which a grandfathered and deemed 

compliant facility can generate RINs 

without complying with the 20% GHG 

reduction threshold to the capacity 

volume specified in a state or Federal 

air permit or the greater of nameplate 

capacity or actual production. This 

approach is similar to how we have 

treated small refiner flexibilities under 

our other fuel rules. As a sub-option to 

this approach, we also seek comment on 

a provision whereby facilities would 

lose their status if they switch to a 

process fuel or feedstock which results 

in an increase of GHG emissions. 

(1) Increases in Volume of Renewable 

Fuel Produced at Grandfathered 

Facilities due to Expansion 

For facilities that commenced 

construction prior to December 19, 

2007, we are proposing to define the 

baseline volume of renewable fuel 

exempt from the 20% GHG threshold 

requirement to be the maximum 

volumetric capacity of the facility as 

allowed in any applicable state air 

permit or Federal Title V operating 

permit. If the capacity of a facility is not 

stipulated in such air permits, then the 

grandfathered volume is the greater of 

the nameplate capacity of the facility or 

historical annual peak production prior 

to enactment of EISA. Volumes greater 

than this amount which may typically 

be due to expansions of the facility 

which occur after December 19, 2007, 

would be subject to the 20% GHG 

reduction requirement in order for the 

facility to generate RINs for the 

incremental expanded volume. The 

increased volume would be considered 

as if produced from a ‘‘new facility’’ 

which commenced construction after 

December 19, 2007. Changes that might 

occur to the mix of renewable fuels 

produced within the facility would 

remain grandfathered as long as the 

overall volume fell within the baseline 

volume. 

The baseline volume would be 

defined as above for deemed compliant 

facilities with the exception that if the 

maximum capacity is not stipulated in 

air permits, then the exempt volume 

would be the maximum annual peak 

production during the plant’s first three 

years of operation. In addition, any 

production volume increase that is 

attributable to construction which 

commenced prior to December 31, 2009 

would be exempt from the 20% GHG 

threshold, provided that the facility 

continued to use natural gas, biomass or 

a combination thereof for process 

energy. Because deemed compliant 

facilities owe their status to the fact that 

they use natural gas, biomass or a 

combination thereof for process heat, we 

propose that their status would be lost, 

and they would be subject to the 20% 

GHG threshold requirement, at any time 

that they change to a process energy 

source other than natural gas and/or 

biomass. Finally, because EISA limits 

deemed compliant facilities to ethanol 

facilities, we propose that if there are 

any changes in the mix of renewable 

fuels produced by the facility that only 

the ethanol volume remain 

grandfathered. We solicit comment, 

however, on whether the statute could 

be read to allow deemed compliant 

facilities to be treated the same as 

grandfathered facilities by allowing a 

mix of renewable fuels. 

Volume limitations contained in air 

permits may be defined in terms of peak 

hourly production rates or a maximum 

annual capacity. If they are defined only 

as maximum hourly production rates, 

they would need to be converted to an 

annual rate. We believe that assuming 

24-hour per day production over 365 

days per year (8,760 production hours) 

may overstate nameplate capacity. In 

other regulations that pertain to refinery 

operations, we have assumed a 

conversion rate of 90% of the total 

hours in a year (7884 production hours). 

We seek comment on what would be an 

appropriate conversion rate for 

renewable fuel facilities. 

The facility registration process (see 

Section III.C) would be used to define 

the baseline volume for individual 

facilities. Owners and operators would 

submit information substantiating the 

nameplate capacity of the plant, as well 

as historical annual peak capacity if 

such is greater than nameplate capacity. 

Subsequent expansions at a 

grandfathered that result in an increase 

in volume would subject the increase in 

volume to the 20% GHG emission 

reduction threshold (but not the original 

baseline volume). Thus, any new 

expansions would need to be designed 

to achieve the 20% GHG reduction 

threshold if the facility wants to 

generate RINs for that volume. Such 

determinations would be made on the 

basis of EPA-defined corn ethanol fuel 

pathway categories that are deemed to 

represent such 20% reduction. As an 

alternative approach to the greater of 

nameplate capacity or historical annual 

peak capacity, we seek comment on an 

approach in which the baseline volume 

is the actual volume of renewable fuel 

produced during the 2006 calendar year, 

where adequate data is available. Since 

there has been a particularly high 

demand for ethanol in recent years, the 

use of 2006 data may be a fair 

representation of the real production 

capacity for most plants. For plants that 

have not operated for an adequate shake 

down period, the information in the 

state or Federal air permit could be used 

and if this is not available, the 

nameplate capacity could be used. As 

mentioned above, deemed compliant 

facilities would be exempt from the 

20% GHG threshold for baseline 

volumes and any additional volumes 

regarding which construction 

commenced prior to December 31, 2009. 

We recognize, however, that some 

debottlenecking type changes may cause 

increases in volume that are within a 

plant’s inherent capacity. To account for 

this in past regulations (e.g., 40 CFR 

80.552 and 554) we allowed for an 

increase of 5% above the baseline 

volume. Based on conversations with 

builders of ethanol plants, however, 

such plants have often been 

debottlenecked to exceed nameplate 

capacity by 20% and sometimes much 

higher. We seek comment on whether 

we should allow a 10% tolerance on the 

baseline volume for which RINs can be 

generated without complying with the 

20% GHG reduction threshold. Once 

that 10% increase in volume is 

exceeded, the total increase above 

baseline volume would then be subject 

to the 20% GHG reduction requirement 

in order to generate RINs. We also seek 

comment on tolerance values in the 5 to 

20% range. 

Our guiding philosophy of protecting 

historical business investments that 

were made to comply with the 

provisions of RFS1 is realized by 

allowing production increases within a 

plant’s inherent capacity. At the same 

time, the alternative of requiring 

compliance with the 20% GHG 

reduction requirement for increases in 

volume above 10% over the baseline 

volume, would place new volumes from 

grandfathered facilities on a level 

playing field with product from new 

grass roots facilities. We believe that a 

level playing field for new investments 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24927 

is fair and consistent with the 

provisions of EISA. 

(2) Replacements of Equipment 

If production equipment such as 

boilers, conveyors, hoppers, storage 

tanks and other equipment are replaced, 

it would not be considered construction 

of a ‘‘new facility’’ under this option of 

today’s proposal—the baseline volume 

of fuel would continue to be exempt 

from the 20% GHG threshold. We 

discuss in a sub-option in III.B.3.c.i(4) 

below in which if the replacement unit 

uses a higher polluting fuel in terms of 

GHG emissions such replacement would 

render the facility a new facility, and it 

would no longer be exempt from the 

20% GHG threshold. We also solicit 

comment on an approach that would 

require that if coal-fired units are 

replaced, that the replacement units 

must be fired with natural gas or biofuel 

for the product to be eligible for RINs 

that do not satisfy the 20% GHG 

threshold. 

(3) Registration, Recordkeeping and 

Reporting 

Facility owner/operators would be 

required to provide evidence and 

certification of commencement of 

construction. Owner/operators must 

provide annual records of process fuels 

used on a BTU basis, feedstocks used 

and product volumes. For facilities that 

are located outside the United States 

(including outside the Commonwealth 

of Puerto Rico, the U.S. Virgin Islands, 

Guam, American Samoa, and the 

Commonwealth of the Northern Mariana 

Islands) owners would be required to 

provide certification as well. Since the 

definition of commencement of 

construction includes having all 

necessary air permits, we would require 

that facilities outside the United States 

to certify that such facilities have 

obtained all necessary permits for 

construction and operation required by 

the appropriate national and local 

environmental agencies. 

(4) Sub-Option of Treatment of Future 

Modifications 

We seek comment on a sub-option to 

the basic approach whereby facilities 

would lose their grandfathered status if 

they switch to a process fuel or 

feedstock which results in an increase of 

GHG emissions. Some facilities may 

keep production volumes the same, but 

change some or all of their feedstocks 

and energy sources, thus causing a 

facility’s product to fall further below 

the GHG performance for the fuel 

pathway it produced at the time of 

enactment. We are therefore seeking 

comment on an approach to limit the 

initial grandfathering only for the fuel 

pathways that applied during 2007, 

when establishing the volume baseline. 

Table III.B.3.c.i–1 below presents a 

ranking of fuels and feedstock by fuel 

pathway in order of life cycle GHG 

emissions (as discussed further in 

Section VI.E). (Table III.B.3.c.i–1 is 

based on the table of fuel pathways 

contained in proposed regulations 40 

CFR 80.1426.) Since the majority of 

facilities under consideration in this 

portion of the rulemaking consists of 

ethanol plants, the table below is 

limited to those types. Any changes to 

a facility that shift it to a feedstock or 

use of a process energy source that 

results in higher GHG emissions on the 

basis of the ranking categories in Table 

III.B.3.c.i–1 below would terminate the 

facility’s grandfathered status. 

For example, an ethanol dry mill 

plant using natural gas for process heat, 

as well as combined heat and power 

(CHP), is ranked as ‘‘2’’ in the table 

below. If the plant (or any portion of the 

plant) switches to coal, it is ranked as 

‘‘4’’. The higher number indicates an 

increase in GHG emissions. Therefore in 

this example, the plant is considered to 

have undertaken a modification that 

increases GHG emissions, would render 

the facility as ‘‘new’’ and its 

grandfathered status would end. 

Similarly, replacements of equipment 

that worsen GHG emissions would also 

terminate grandfathered status. (For 

replacements of equipment that do not 

change the fuel, nor result in an increase 

in volume of renewable fuel, the 

grandfathered status of the plant would 

remain, as discussed in Section 

III.B.3.c.i(2) above.) 

TABLE III.B.3.c.I–1—GROUPS OF RENEWABLE FUEL FACILITIES BY FUEL FEEDSTOCK AND PROCESS ENERGY

Feedstock Production process requirements Ranking 

Starch from corn, wheat, barley, oats, rice, or sorghum .............. —Process heat derived from biomass ........................................ 1 

Starch from corn, wheat, barley, oats, rice, or sorghum .............. —Dry mill plant ............................................................................ 2 

—All process heat derived from natural gas.

—Combined heat and power (CHP).

—Fractionation of feedstocks.

—Dried distillers grains.

Starch from corn, wheat, barley, oats, rice, or sorghum .............. —Dry mill plant ............................................................................ 3 

—All process heat derived from natural gas.

—Wet distillers grains.

Starch from corn, wheat, barley, oats, rice, or sorghum .............. —Dry mill plant ............................................................................ 4 

—All or part of process heat derived from coal.

—Combined heat and power (CHP).

—Fractionation of feedstocks.

—Membrane separation of ethanol.

—Raw starch hydrolysis.

—Dried distillers grains.

Starch from corn, wheat, barley, oats, rice, or sorghum .............. —Dry mill plant ............................................................................ 5 

—All or part of process heat derived from coal.

—Combined heat and power (CHP).

—Fractionation of feedstocks.

—Membrane separation of ethanol.

—Wet distillers grains.

Sugarcane sugar ........................................................................... —Process heat derived from sugarcane bagasse ...................... 1 

Sugarcane sugar ........................................................................... —Process heat derived from natural gas .................................... 2 

Sugarcane sugar ........................................................................... —Process heat derived from coal ............................................... 3 

24928 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

9 Kwiatkowski, J.R., McAloon, A., Taylor, F. 

Johnson, D. 2006. ‘‘Modeling the process and costs 

of fuel ethanol production by the corn dry-grind 

process.’’ Industrial Crops and Products 23 (2006) 

288–296. 

10We note that under NSPS the costs considered 

in determining whether the definition of 

reconstruction has been met are restricted to the 

capital costs of equipment and materials. The RFS2 

program is authorized from EISA which does not 

rely on the definitions of ‘‘modification’’ and 

‘‘routine maintenance and repair’’ that are in NSPS 

and other new source programs (e.g., New Source 

Review, National Emission Standards for Hazardous 

Pollutants). Since our application of the term 

‘‘reconstruction’’ assumes that over time, renewable 

fuel facilities may become substantially rebuilt it is 

therefore appropriate to consider not only 

equipment replacements but some of the labor costs 

associated with such replacements. 

We considered whether 

improvements at a facility (i.e., a fuel 

switch from coal to natural gas) that still 

result in GHG performance less than 

20% should be credited to allow the 

facility to increase its baseline volume. 

We decided not to propose such an 

approach because it would take away an 

incentive for new plants that achieve 

greater than 20% GHG reduction to be 

constructed. As such, this would go 

against our guiding principle of 

providing equal opportunities for future 

investments in new plants. 

We recognize that there may be 

combinations of changes made at a 

plant, some of which may worsen GHG 

emissions and others which may cause 

an improvement and that not all such 

combinations can be taken into account 

in a single table of fuel pathways. We 

seek comment on ways to address such 

combinations. 

ii. Alternative Options for Which We 

Seek Comment 

(1) Facilities That Meet the Definition of 

‘‘Reconstruction’’ Are Considered New 

An alternative approach on which we 

are seeking comment would consider 

whether a facility is effectively a ‘‘new’’ 

facility with respect to the costs 

incurred in maintaining the plant over 

time. Starting in 2010, we would require 

facility owners to report annually 

(specifically by January 31) to EPA the 

expenses for replacements, additions, 

and repairs undertaken at facilities since 

start up of the facility through the year 

prior to reporting. The Agency would 

then determine whether the degree of 

such activities warrants considering the 

facility as effectively ‘‘new’’. That 

substantial rebuilding or modernization 

may render an existing facility a new 

facility for regulatory purposes finds 

analogies in other Clean Air Act 

regulatory programs. For example, 

under the New Source Performance 

Standards (NSPS) equipment that has 

been ‘‘reconstructed’’ as defined in 40 

CFR 60.15 is considered new. 

Specifically, ‘‘reconstruction’’ is defined 

in 40 CFR 60.15 as ‘‘the replacement of 

components of an existing facility to 

such an extent that the fixed capital cost 

of the new components exceeds 50% of 

the fixed capital cost that would be 

required to construct a comparable 

entirely new facility. In addition to the 

NSPS program, regulations such as the 

recently promulgated standards for 

locomotive and marine engines (73 FR 

25160; May 6, 2008) use a more 

encompassing concept of reconstruction 

and consider a vessel to be new if it is 

modified such that the value of the 

modifications exceeds 50% of the value 

of the modified vessel. We are seeking 

comment on an approach wherein upon 

the Agency’s determination that costs of 

replacements, repairs and upgrades 

conducted since the start-up of the 

facility meet the test of ‘‘reconstruction’’ 

(i.e., the costs equal or exceed 50% of 

what it would cost to rebuild), that the 

facility would be considered effectively 

new, and would be subject to the 20% 

GHG reduction requirements. 

The application of the definition of 

reconstruction in the NSPS program 

occurs on an equipment-wide rather 

than on a plant-wide basis. Under this 

option, we would apply the concept of 

a ‘‘new’’ facility on a plant-wide basis 

similar to the approach we have taken 

in the recently promulgated locomotive 

and marine standards. We believe that 

a plant-wide approach is appropriate 

under RFS2 because it is not the 

emissions from individual pieces of 

equipment that are being regulated. 

Rather, the 20% GHG reduction 

standard applies to the renewable fuel 

produced by the facility, and it is logical 

to consider all of the equipment and 

structures at the facility involved in 

producing the product in evaluating 

when a grandfathered facility has been 

reconstructed. For these reasons, we 

believe that it would be reasonable to 

apply the definition of ‘‘new’’ on a 

plant-wide basis. Also, since upgrades, 

replacements and repairs will occur on 

an ongoing basis we would consider 

rebuilding or reconstruction to occur 

over time as the accumulation of all 

individual upgrades, replacements and 

repairs. 

The NSPS definition also requires that 

it be ‘‘technologically and economically 

feasible for the reconstructed facility to 

meet applicable standards that apply to 

new facilities.’’ We do not think that 

EISA requires this additional 

consideration, and also do not believe 

that there is any compelling public 

policy justification for allowing a 

reconstructed facility to continue to 

make renewable fuel that does not meet 

the 20% GHG reduction standard based 

upon a claim that it is technologically 

or economically infeasible. EPA’s 

experience in the New Source Review 

(NSR) program has demonstrated that it 

is extremely difficult to clearly define 

what the terms ‘‘technologically and 

economically feasible’’ mean. Aside 

from such definitional difficulties, 

however, and as discussed in Section 

III.B.3.c.ii(2) below, we believe that it is 

technologically feasible to meet the 20% 

GHG reduction and with proper 

planning would be economically so, as 

well. Therefore, this alternative option 

would not require such a showing. 

Our assessment of whether a facility 

has been reconstructed would be based 

on application of an appropriate cost 

model such as U.S. Department of 

Agriculture’s cost estimation model for 

construction of new ethanol plants 

described by Kwiatkowski, J. et al. 

(2006) 9. Costs associated with the costs 

of repair and replacement of all parts 

(including the labor associated with 

replacement and repair), would be 

included in such calculation, regardless 

of the parts’ intended useful life. We 

seek comment on whether to also 

include costs associated with employee 

labor related to routine maintenance, 

and also whether the costs of repairs 

and replacements at the facility should 

be limited only to the property directly 

related to the production of biofuels.10

Under this alternative option, the 

volume of renewable fuel that qualifies 

for an exemption from the 20% GHG 

threshold would remain fixed at the 

baseline volume as in the basic option 

described in III.B.3(c)(i). However, we 

also seek comment on whether the 

volume of renewable fuel at a 

grandfathered facility should be allowed 

to increase above baseline volumes 

under this option. Specifically, 

increases in volume could be exempt 

until such time as the entire plant is 

deemed to have been reconstructed. In 

making such assessment and applying 

the 50% test, the basis for the cost of a 

‘‘comparable entirely new facility’’ 

would be a facility with the original 

baseline volume. For example, if an 

existing plant has a 100 million gallon 

per year capacity and expands its 

volume to 120 million gallons per year, 

reconstruction would occur if the costs 

incurred over time equal or exceed 50% 

of the cost of a comparable 100 million 

gallon per year facility. 

Under this alternative option, owner/ 

operators or other responsible parties 

would be required to provide records of 

costs incurred for additions, 

replacements, and repairs that have 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24929 

11Nilles, D. 2006. ‘‘Time Testing’’; Ethanol 

Producer Magazine, May, Vol. 12, No. 5. 

12Op Cit., Kwiatkowski, et al. (2006). 

13Note to Docket (EPA–HQ–OAR–2005–0161), 

‘‘Analysis of Costs of Replacements and Repairs at 

a Hypothetical 100 MM GPY Ethanol Facility’’; 

from Barry Garelick, Environmental Protection 

Specialist, Assessment and Standards Division, 

Office of Transportation and Air Quality; October 

16, 2008. 

14The USDA model gives the installed capitol 

cost of a 40 million GPY facility at approximately 

$60 million (2006 dollars). The model also gives 

replacement costs of individual components (steel 

tanks and the ring dryer) at about $13 million. 

Ongoing maintenance costs are estimated at about 

$6 million per year. 

15Unless and until EPA conducts facility specific 

life cycle analyses, however, compliance with the 

20% GHG reduction threshold would be made on 

the basis of fuel pathways as described in Section 

III.D.2. 

occurred since start-up. Such records 

would be provided on an annual basis 

to EPA by May 31, and would include 

cumulative cost information up to the 

prior year. 

We recognize that implementation of 

a facility-wide definition of 

‘‘reconstruction’’ would be complex. 

Records of costs since start-up may not 

be available for older facilities. Also, 

this alternative option requires EPA 

enforcement staff to have sufficient 

financial knowledge and experience to 

be able to evaluate the veracity of claims 

regarding various types of expenditures. 

Calculating the costs of repairs and 

replacements also poses challenges. 

Specifically, as discussed above, we 

seek comment on whether the costs of 

routine maintenance and repair should 

be included in such assessments. Were 

such costs to be included, the 

determination of whether a replacement 

or a repair is routine may not always be 

straightforward. In addition to the 

recordkeeping and implementation 

issues, however, there is an important 

policy consideration that is also 

significant. As in the case of the NSR 

program, where many industry 

representatives have argued that the 

program has a chilling effect on projects 

that could provide environmental 

benefits, the reconstruction approach in 

this alternative option could also 

provide a disincentive to 

implementation of safety and 

environmental projects. Thus, this 

option could have the unintended 

consequence of causing facilities to 

refrain from investing in projects that 

will increase safety and efficiency and 

reduce emissions in order to avoid 

triggering the 50% cost threshold. We 

seek comment on this issue. 

(2) Expiration Date of 15 Years for 

Exempted Facilities 

The above discussion highlights 

potential complexities in implementing 

the option of considering reconstruction 

of exempted facilities on a case-by-case 

basis. These include potential disputes 

over how to calculate costs, as well as 

verifying records of expenditures. In 

addition, that option has as a potential 

unintended consequence, a disincentive 

for investment in projects that could 

improve safety, efficiency and 

environmental performance. As an 

alternative to the case-by case approach 

described above, this option offers a 

practical way of implementing the 

reconstruction concept by establishing 

an expiration date for all grandfathered 

and deemed compliant facilities after a 

period of 15 years from enactment of 

EISA (i.e., after December 31, 2022), 

regardless of when such facilities 

commenced construction or began 

operation. Under such option, the 

grandfathered and deemed compliant 

facilities would be subject to the 20% 

GHG threshold starting on January 1, 

2023. Renewable fuel produced from 

these facilities after this date would be 

required to comply with the 20% 

threshold requirement in order to 

generate RINs. 

Based on our discussions with 

companies that construct ethanol plants, 

we believe that facility owners will 

make decisions about equipment 

replacements and technology upgrades 

that will continue to improve the overall 

operating costs and energy efficiency of 

the plant which ultimately lead to 

improvements in GHG emission 

performance as well. In particular, 

energy-intensive processes in the plant 

are likely to be replaced or upgraded to 

increase fuel and operating efficiency, 

thus reducing operating costs of the 

plant, and increasing output. Nilles 

(2006) reports that the first line of nextgeneration dry-grind ethanol plants was 

built with mild steel components and 

that in 10 or 15 years, those components 

will need to be replaced entirely—most 

likely with stainless steel. Of particular 

importance is that durable materials as 

well as weaker materials all require 

maintenance and replacement. As such, 

the components and equipment in 

ethanol facilities are designed to be 

easily replaced and to allow simple 

maintenance.11

Using cost data contained in the U.S. 

Department of Agriculture’s cost 

estimation model for construction of 

new ethanol plants described by 

Kwiatkowski, J. et al (2006), we 

calculated the cost of a replacement of 

specific components in a hypothetical 

100 million gallon ethanol facility.12 13

We assumed that all steel tanks are 

replaced with stainless steel tanks, and 

that specific combustion equipment is 

replaced. Combining replacement costs 

with maintenance, repairs, upgrades 

and supply costs (at 2% of the capital 

cost of the facility per year), we 

calculated that over 15 years, the 

accumulated costs range from 50% to 

75% of the capital cost of an equivalent 

facility.14

As discussed in Section 1.5.1.3 of the 

DRIA, per our conversations with 

builders of ethanol plants, the changes 

and upgrades would be made to 

improve competitiveness which will 

also improve operating and fuel 

efficiency, thus tending to improve 

overall GHG performance of the plant. 

The high price of natural gas has many 

ethanol plants considering alternative 

fuel sources. Greater biofuel availability 

and potential low life cycle green house 

gas emissions incentives may further 

encourage ethanol producers to switch 

from fossil fuels for process heat to 

biomass based fuels. In addition, 

ethanol producers may consider energy 

saving changes to the ethanol 

production process. Several process 

changes, including raw starch 

hydrolysis, corn fractionation, corn oil 

extraction, and membrane separation, 

are likely to be adopted to varying 

degrees. Since such changes would be 

consistent with ultimately achieving the 

20% GHG reduction required of new 

facilities, we believe it is reasonable to 

expect that the newly rebuilt facilities 

could meet the 20% GHG reduction 

threshold, based on the results of a life 

cycle analysis.15

We solicit further information and 

data, particularly evidence of the types 

of replacements and ongoing 

maintenance that has occurred at 

existing plants and what is projected to 

occur in the future. We will evaluate 

such information along with other 

comments received during the public 

comment period. We also solicit 

comment on whether a period other 

than 15 years may be more appropriate. 

Under this approach, facilities that are 

exempted could expand their volume of 

renewable fuel production, or could 

switch fuels or feedstocks within the 15 

year exemption period without fear of 

losing their temporary exemption. 

While some of these activities have the 

potential to worsen GHG emissions 

further below the 20% threshold 

requirement, we believe that the 

imposition of an expiration date will 

result in modifications to facilities that 

tend to increase the efficiency and GHG 

performance of the plant rather than 

worsen them. The need for compliance 

with the 20% threshold requirement by 

a date certain would provide an 

incentive for owners and operators of 

24930 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

16Specifically, Table B–2 of IRS Publication 946, 

‘‘How To Depreciate Property’’ provides class lives 

and recovery periods for use in computing 

depreciation for asset classes categorized by SIC 

codes. Ethanol facilities (which are in SIC 28, 

Manufacture of Chemical and Allied Products) is 

given a class life of 10 years. For facilities that 

qualify for Modified Accelerated Cost Recovery 

System (MACRS), the period is 7 years. 

such plants to ensure the changes they 

make over time would bring them into 

compliance with the 20% requirement 

at the end of the 15 year period. 

While the facilities built in 2008 and 

2009 would be in operation for less than 

15 years, the majority of ethanol plants 

will have been in operation for 15 years 

or longer. As discussed in Section V.B.1, 

approximately 15 billion gallons of corn 

ethanol production capacity is currently 

online, idled or under construction. 

While some of these plants/projects are 

currently on hold due to the economy, 

we anticipate that this corn ethanol 

capacity will come online in the future 

under the proposed RFS2 program. And 

the majority of these plants commenced 

construction prior to 2008. We solicit 

comment, however, on whether there 

should be a plant-specific expiration 

date of 15 years after commencement of 

operations for deemed compliant 

facilities that commenced construction 

in 2008 or 2009. Under this sub-option, 

the expiration date for such plants 

would be 15 years from the time the 

facility began operation, per registration 

made by the owner of the facility. 

The option of limiting the exemption 

period to 15 years or other specific time 

period offers certainty to industry for a 

15 year period, and also certainty that 

at the end of that time period they will 

be subject to the 20% GHG reduction 

threshold. This time period could be 

used by facility owners to ensure the 

facility will ultimately meet the 

requirement. Finally, the option ensures 

that investments made in equipment to 

comply with RFS1 requirements are 

protected with respect to being fully 

depreciated for tax purposes.16

Furthermore, this approach is easy to 

implement, and avoids case-by-case 

determinations that can extremely be 

time-consuming, contentious, and costly 

for both industry and EPA. In addition, 

because the exemption expiration date 

would apply to all facilities, this option 

would provide no incentive to delay 

modifications that increase energy 

efficiency, safety, or improve 

environmental performance unlike the 

option described above involving caseby-case consideration of reconstruction. 

(3) Expiration Date of 15 Years for 

Grandfathered Facilities and Limitation 

on Volume 

We also seek comment on a hybrid 

approach in which an expiration date of 

15 years is established for grandfathered 

and deemed compliant facilities, but 

prior to then, the facilities’ exemption 

from the 20% GHG threshold would be 

limited to their baseline volumes, as in 

the option described in Section III.B.3.c. 

(4) ‘‘Significant Production Units’’ Are 

Defined as Facilities 

We seek comment on an approach in 

which ‘‘facility’’ would be defined on 

the basis of ‘‘significant production 

units’’. For example, the regulations 

regarding air toxic emissions for the 

miscellaneous organic chemical 

manufacturing industry (which includes 

ethanol manufacturing plants) under 

NESHAPS (40 CFR 2440(c)) apply to 

miscellaneous chemical process units 

and heat exchangers within a single 

facility. This option, therefore, would 

follow a similar approach, and treat as 

new facilities subject to the 20% GHG 

reduction requirement any new 

significant production units. 

Defining ‘‘facility’’ as a significant 

production unit would raise the 

question of when an increase in volume 

due to the addition of specific pieces of 

equipment should be considered 

augmenting current production lines as 

opposed to being a new production line. 

We solicit comment on this approach as 

well as how the term ‘‘significant 

production unit’’ would need to be 

defined in the regulations to avoid 

ambiguity. Any incidental increases in 

volume due to the addition of pieces of 

equipment that would not constitute a 

new ‘‘significant production unit’’ line 

would continue to be grandfathered, as 

would increases in volume associated 

with changes made to debottleneck the 

facility. 

(5) Indefinite Grandfathering and No 

Limitations Placed on Volume 

Under our basic option, described in 

Section III.B.3.c.i, we would interpret 

the statutory language to mean that 

expansions of grandfathered facilities 

after enactment of EISA and which 

expand volume beyond a plant’s 

inherent capacity are not among those 

that qualify for an exemption from the 

20% GHG reduction requirement. 

Otherwise, a facility that qualifies for 

grandfathering could be expanded by 

any amount, and the additional volume 

would also receive protection. We do 

not believe that this was the intent of 

the language in EISA. Nevertheless, we 

recognize that there are alternative 

interpretations of the statute and 

therefore seek comment on an 

alternative that places no limitations on 

the volume of renewable fuel from 

grandfathered or deemed compliant 

facilities. Under such option, ‘‘new 

facility’’ would be defined solely as a 

new ‘‘greenfield’’ plant. 

4. Renewable Biomass With Land 

Restrictions 

As explained in Section III.B.1.a, 

EISA lists seven types of feedstock that 

qualify as ‘‘renewable biomass’’: 

1. Planted crops and crop residue. 

2. Planted trees and tree residue. 

3. Animal waste material and animal 

byproducts. 

4. Slash and pre-commercial 

thinnings. 

5. Biomass obtained from the vicinity 

of buildings at risk from wildfire. 

6. Algae. 

7. Separated yard or food waste. 

EISA limits not only the types of 

feedstocks that can be used to make 

renewable fuel, but also the land that 

several of these renewable fuel 

feedstocks may come from. Specifically, 

EISA’s definition of renewable biomass 

incorporates land restrictions for 

planted crops and crop residue, planted 

trees and tree residue, slash and precommercial thinnings, and biomass 

from wildfire areas. EISA does not 

prohibit the production of renewable 

fuel feedstock that does not meet the 

definition of renewable biomass, nor 

does it prohibit the production of 

renewable fuel from feedstock that does 

not meet the definition of renewable 

biomass. It does, however, prohibit the 

generation of RINs for renewable fuel 

made from feedstock that does not meet 

the definition of renewable biomass, 

which includes not meeting the 

associated land restrictions. The 

following sections discuss the 

challenges of implementing the land 

restrictions contained in the definition 

of renewable biomass and propose 

approaches for establishing a workable 

implementation scheme. 

a. Definitions of Terms 

EISA’s descriptions of four feedstock 

types noted above—planted crops and 

crop residue, planted trees and tree 

residue, slash and pre-commercial 

thinnings, and biomass from wildfire 

areas—contain terms that can be 

interpreted in multiple ways. The 

following sections discuss our proposed 

interpretations for many of the terms 

contained in EISA’s definition of 

renewable biomass. In developing this 

proposal, we consulted many sources, 

including the USDA, as well as 

stakeholder groups, in order to 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24931 

17Natural Resource Conservation Service, USDA, 

‘‘Natural Resources Inventory 2003 Annual NRI,’’ 

February 2007. Available at http:// 

www.nrcs.usda.gov/technical/NRI/2003/Landusemrb.pdf. 

determine the range of possible 

interpretations for these different terms. 

We have made every attempt to define 

these terms as consistently with USDA 

and industry standards as possible, 

while keeping them workable for 

purposes of program implementation. 

We seek comment on our proposed 

definitions of important terms in the 

following sections. 

i. Planted Crops and Crop Residue 

The first type of renewable biomass 

described in EISA is planted crops and 

crop residue harvested from agricultural 

land cleared or cultivated at any time 

prior to December 19, 2007, that is 

either actively managed or fallow, and 

nonforested. We propose to interpret the 

term ‘‘planted crops’’ to include all 

annual or perennial agricultural crops 

that may be used as feedstock for 

renewable fuel, such as grains, oilseeds, 

and sugarcane, as well as energy crops, 

such as switchgrass, prairie grass, and 

other species, providing that they were 

intentionally applied to the ground by 

humans either by direct application as 

seed or nursery stock, or through 

intentional natural seeding by mature 

plants left undisturbed for that purpose. 

Many energy crops that could be used 

for cellulosic biofuel production, 

especially perennial cover plants, are 

currently grown in the U.S. without 

significant agronomic inputs such as 

fertilizer, pesticides, or other chemical 

treatment. These crops may be 

introduced or indigenous to the area in 

which they grow, and may have been 

originally planted decades ago. We 

propose to include this type of 

vegetation as a planted crop with the 

recognition that it may include some 

plants that were intentionally naturally 

generated, i.e., resulted from natural 

seeding from existing plants, and not 

planted through direct human 

intervention. We believe that given the 

increasing importance under RFS2 of 

biofuels produced from cellulosic 

feedstocks, such as switchgrass and 

other grasses, such a definition is 

appropriate. We note that because EISA 

contains specific provisions for planted 

trees and tree residue from tree 

plantations, we propose that the 

definition of planted crops in EISA 

exclude planted trees, even if they may 

be considered planted crops under some 

circumstances. 

We further propose that ‘‘crop 

residue’’ be limited to the residue left 

over from the harvesting of planted 

crops, such as corn stover and sugarcane 

bagasse. However, we seek comment on 

an alternative interpretation that would 

include as crop residue biomass from 

agricultural land removed for purposes 

of invasive species control or fire 

management. In that context ‘‘crop 

residue’’ would include any biomass 

removed from agricultural land that 

facilitates crop management, whether or 

not the crop itself is part of the residue. 

Our proposed regulations would 

restrict planted crops and crop residue 

to that harvested from existing 

agricultural land. With respect to what 

land would qualify as agricultural land, 

we first turned to the mutually 

exclusive categories of land defined by 

USDA’s Natural Resources Conservation 

Service (NRCS) in its annual Natural 

Resources Inventory (NRI), a statistical 

survey designed to estimate natural 

resource conditions and trends on nonfederal U.S. lands.17 The categories used 

in the NRI are cropland, pastureland, 

rangeland, forest land, Conservation 

Reserve Program (CRP) land, federal 

land, developed land, and ‘‘other rural 

land.’’ We have chosen to include in our 

proposed definition of agricultural land 

three of these land categories— 

cropland, pastureland, and CRP land. 

Using the NRI descriptions of these land 

types as models, we developed 

definitions for these land types for this 

proposal. 

We propose to define cropland as 

land used for the production of crops for 

harvest, including cultivated cropland 

for row crops or close-grown crops and 

non-cultivated cropland for 

horticultural crops. Corn, wheat, barley, 

and soybeans are renewable fuel 

feedstocks that would be grown on 

cropland. We propose to define 

pastureland as land managed primarily 

for the production of indigenous or 

introduced forage plants for livestock 

grazing or hay production, and to 

prevent succession to other plant types. 

Under this proposed definition, land 

would qualify as pastureland if it is 

maintained for grazing or hay 

production and not allowed to develop 

greater ecological diversity. Switchgrass 

is one example of a renewable fuel 

feedstock that could be grown on 

pastureland. 

We also propose that CRP land be 

counted as ‘‘agricultural land’’ under 

RFS2. The CRP is administered by 

USDA’s Farm Service Agency and is 

designed to promote restoration of 

environmentally sensitive lands by 

offering annual rental payments in 

return for removing land from 

cultivation over a period of several 

years. To qualify for the CRP, land had 

to have been used for agricultural 

production for at least three years prior 

to entering the program. For this reason, 

we believe it is appropriate to propose 

that CRP land be included under the 

rubric of agricultural land. 

In addition, we seek comment on 

whether rangeland should be included 

as agricultural land under RFS2. 

Rangeland is land on which the 

indigenous or introduced vegetation is 

predominantly grasses, grass-like plants, 

forbs or shrubs and which—unlike 

cropland or pastureland—is 

predominantly managed as a natural 

ecosystem. Given the relative lower 

degree of management of such lands, it 

is questionable whether any rangeland 

should qualify as ‘‘actively managed’’ 

under EISA (a general discussion on our 

proposed interpretation of the term 

‘‘actively managed’’ is presented later in 

this section). On the other hand, we 

understand that there is frequently some 

degree of management on such lands, 

such as controlling invasive species, 

managing grazing rates, fencing, etc. 

Therefore, we believe that there may 

be merit in allowing planted crops and 

crop residue from rangeland to qualify 

as renewable biomass under this 

program. This would allow, for 

example, existing switchgrass or native 

grasses on rangeland to be used for 

renewable fuel production that qualifies 

for RIN generation under this program. 

However, we are not proposing to 

include rangeland as agricultural land 

due to our own implementation 

concerns as well as issues raised by 

stakeholders over the potential for 

providing any incentive for increased 

crop production in rangeland areas. We 

seek comment on the issue and on the 

points raised in the following 

discussion. 

Allowing rangeland to qualify as 

agricultural land under RFS2 would 

make millions of acres of additional 

non-cropland, non-forested land qualify 

for renewable fuel feedstock production 

in the U.S. This additional land could 

be important to support future 

expansion of dedicated energy crops, 

such as switchgrass and tall prairie 

grass, which currently grow or could 

grow on such lands. The availability of 

rangeland could alleviate some of the 

competition on cropland and 

pastureland for space to grow crops for 

biofuel feedstocks, thereby allowing 

continued growth of food crops on land 

best suited for that specific purpose. It 

would also provide rangeland owners 

with the potential for increased 

revenues from their lands by producing 

feedstocks for renewable fuel, and 

decrease the pressure for such lands to 

be converted to cropland for food crop 

production. 

24932 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

However, we recognize that rangeland 

is a term that can be used to describe a 

wide variety of ecosystems, including 

certain grasslands, savannas, wetlands, 

deserts, and even tundra. These types of 

ecosystems represent land that at best 

could serve only marginally well for 

producing renewable fuel feedstocks, 

and at worst could suffer significantly if 

intensive agricultural practices were 

imposed upon them for purposes of 

producing crops. We also recognize that 

if we were to include rangeland as 

agricultural land under RFS2, there is a 

risk that some rangeland, including 

native grasslands and shrublands, could 

be converted to produce monoculture 

crops. We raise these concerns for two 

reasons. First, certain rangeland cannot 

be used sustainably for agricultural crop 

production, and any such short-term use 

could seriously diminish the long-term 

potential of these lands to be used for 

less-intensive forage production or even 

to return to their previous ecological 

state. Second, conversion of relatively 

undisturbed rangeland to the 

production of annual crops could in 

some cases result in large releases of 

GHGs that have been stored in the soil. 

EPA believes that Congress enacted the 

renewable biomass definition in part to 

minimize GHG releases from land 

conversion, a goal that could be 

undermined by conversion of rangeland 

to intensive crop production under 

RFS2. On the other hand, it may be 

argued that while GHGs would be 

emitted initially, planting dedicated 

energy crops rather than food crops on 

such land could yield more positive 

than negative results over time. Such 

could be the case if the alternative were 

to grow energy crops on cropland, 

consequently displacing food crops to 

other lands, either in the U.S. or abroad. 

This displacement could lead to overall 

higher direct and indirect GHG 

emissions. EPA solicits comment on the 

potential GHG effects if rangeland were 

included as eligible agricultural land 

under RFS2. We are especially 

interested in data that could help us to 

quantify such impacts. 

While enforcement of the overall 

renewable biomass provisions under the 

final RFS2 program is expected to be 

challenging, it is possible that including 

rangeland as qualifying agricultural land 

under the RFS2 program would increase 

enforcement complexity. As discussed 

later in this section, in order to qualify 

as renewable biomass under RFS2, 

agricultural products must come from 

agricultural land that was cleared or 

cultivated at any time prior to 

enactment of EISA, and either actively 

managed or fallow, and nonforested. We 

believe that evidence of past intensive 

use and management of rangeland may 

be considerably more rare, and 

considerably less definitive, than for 

other types of agricultural land. In 

addition, given the continuous, open 

nature of some rangeland, there would 

likely be difficulty in identifying the 

precise boundaries of a parcel of 

qualifying rangeland. EPA seeks 

comment on these issues. 

We thus seek comment on whether or 

not we should include rangeland in the 

definition of ‘‘existing agricultural land’’ 

in the final RFS2 program, as well as 

comment on whether or not the benefits 

of including rangeland exceed the 

disadvantages. We also seek comment 

on how best to define rangeland, and 

whether we can define rangeland in a 

meaningful way such that sensitive 

ecosystems that may generally be 

described as rangeland can be protected 

from cultivation for renewable fuel 

feedstock production. 

Furthermore, EPA solicits comment 

on an alternative option that would 

include rangeland as agricultural land, 

but that would interpret the EISA 

‘‘actively managed’’ criterion in the 

renewable biomass definition (again, 

discussed later in this section) to limit 

the types of planted crops or crop 

residues from specific parcels of land 

that can qualify as renewable biomass 

by reference to the type of management 

(cropland, pastureland, or rangeland) 

being practiced on the date EISA was 

enacted. For example, if at some point 

in the future corn or other row crops are 

grown on land that was pastureland or 

rangeland when EISA was enacted, such 

row crops would not qualify as 

renewable biomass under RFS2. This 

approach could thus reduce the 

incentives for pastureland and 

rangeland owners to convert their land 

to cropland. We believe that this 

approach could have less environmental 

harm than allowing unrestricted use of 

qualifying rangeland for the production 

of crops for renewable fuel production. 

While our proposed implementation 

approach and alternatives are presented 

later in this section, it is important to 

note here that the principal drawback to 

this alternative option involves its 

implementation and enforcement. This 

approach would require that land types 

(again, cropland, pastureland, or 

rangeland) be identified as of the date of 

EISA enactment in order to determine 

which feedstocks grown on such land 

would qualify as renewable biomass. In 

practical terms, such an approach may 

mean, for example, that a renewable fuel 

producer would need to be able to 

identify not only whether a given 

shipment of corn was grown on 

agricultural land cleared or cultivated 

prior to enactment of EISA, but also that 

the land was not previously pastureland 

or rangeland that had been converted to 

cropland after enactment of EISA. If it 

was, it would not qualify as renewable 

biomass. We are concerned that adding 

this additional feedstock verification 

criterion to those already contained in 

this proposal could render the program 

unworkable and unenforceable. 

However, we invite comment on this 

option, and specifically request 

comment on how this option could be 

implemented in a workable and 

enforceable manner. 

In keeping with the statutory 

definition for renewable biomass, we 

propose to include in our definition of 

existing agricultural land the 

requirement that the land was cleared or 

cultivated prior to December 19, 2007, 

and that, since December 19, 2007, it 

has been continuously actively managed 

(as agricultural land) or fallow, and 

nonforested. We believe the language 

‘‘cleared or cultivated at any time’’ prior 

to December 19, 2007, describes most 

cultivable land in the U.S., since so 

much of the country’s native forests and 

grasslands were cleared in the 17th, 

18th, and 19th centuries, if not before, 

for agriculture. We further believe that 

land that was cropland, pastureland, or 

CRP land on December 19, 2007, would 

automatically satisfy this particular 

criterion, and that therefore it is not of 

significant concern from an 

implementation or enforcement 

perspective. 

In the event that we were to include 

rangeland as agricultural land under the 

final RFS2 program, satisfying the 

‘‘cleared or cultivated’’ criterion could 

pose significant challenges. Some 

rangeland has never been cleared or 

cultivated, or may have been cleared or 

cultivated prior to December 19, 2007, 

but no evidence exists to confirm this. 

Therefore, we could not assume that it 

would necessarily meet the ‘‘cleared or 

cultivated’’ criterion. For instance, 

grasslands in the Midwest and West that 

during the Dust Bowl of the 1930s had 

been used for cultivation could meet 

this criterion, but other western 

grasslands and prairies used for cattle 

grazing may not. We seek comment on 

how best to verify that rangeland to be 

used for renewable fuel feedstock 

production was cleared or cultivated at 

some point prior to December 2007. We 

also seek comment on whether the 

challenge associated with applying this 

criterion to rangeland is sufficient 

(alone or combined with the concerns 

raised earlier about the inclusion of 

rangeland in the definition of 

agricultural land) to exclude rangeland 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24933 

from the final definition of agricultural 

land. 

We believe that the more restrictive, 

and therefore more important, criteria is 

whether agricultural land is actively 

managed or fallow, and nonforested, per 

the statutory language. We propose to 

interpret the phrase ‘‘that is actively 

managed or fallow, and nonforested’’ as 

meaning that land must have been 

actively managed or fallow, and 

nonforested, on December 19, 2007, and 

continuously thereafter in order to 

qualify for renewable biomass 

production. We believe this 

interpretation of the legislative language 

is reasonable and appropriate for the 

following reason. The EISA language 

uses the present tense (‘‘is actively 

managed * * *’’) rather than the past 

tense to describe qualifying agricultural 

land. We interpret this language to mean 

that at the time the planted crops or 

crop residue are harvested (i.e., now or 

at some time in the future), the land 

from which they come must be actively 

managed or fallow, and nonforested. 

However, assuming that the land was 

cleared or cultivated at some point in 

time, then any land converted to 

agricultural land after December 19, 

2007, and used to produce crops or crop 

residue would inherently meet the 

definition of ‘‘is actively managed or 

fallow, and nonforested,’’ and the EISA 

land restriction for planted crops and 

crop residue would have little meaning 

(except in cases where it could be 

established that the land in question 

had never been cleared or cultivated). 

We believe that in order for this 

provision to have meaning, we must 

require that agricultural land remain 

‘‘continuously’’ either actively managed 

or fallow, and nonforested, since 

December 19, 2007. In this way, the 

upper bound on acreage that qualifies 

for planted crop and crop residue 

production under RFS2 would be 

limited to existing agricultural land— 

cropland, pastureland, or CRP land—as 

of December 19, 2007, and the phrase 

‘‘is actively managed or fallow, and 

nonforested’’ would be interpreted in a 

meaningful way. 

We propose that ‘‘actively managed’’ 

would mean managed for a 

predetermined outcome as evidenced by 

any of the following: sales records for 

planted crops, crop residue, or 

livestock; purchasing records for land 

treatments such as fertilizer, weed 

control, or reseeding; a written 

management plan for agricultural 

purposes; documentation of 

participation in an agricultural program 

sponsored by a Federal, state or local 

government agency; or documentation 

of land management in accordance with 

an agricultural certification program. 

Examples of government programs or 

product certification programs that 

would indicate active agricultural land 

management include USDA’s certified 

organic program or the Federal Crop 

Insurance program. 

We realize that it may be difficult to 

conclude that certain land has been 

actively managed continuously since 

December 2007 based solely on the 

existence of receipts for fertilizer or 

seed. However, we have included sales 

and purchasing records in the list of 

written documentation that could be 

used to indicate active management due 

to the fact that there may be qualifying 

land that is not registered with any 

formal agricultural program, for which 

the owner does not receive government 

benefits, and for which no written 

management plan exists (or existed as of 

December 2007). We believe this may be 

the case especially for pastureland from 

which no crops are harvested or sold. 

Other evidence that could be used 

regarding the consistent management of 

pastureland since December 2007 are 

records associated with the sale of 

livestock that grazed on the land. We 

seek comment on our proposal to 

include relevant records of sales and 

purchasing as adequate documentation 

to prove that land was actively managed 

since December 2007 and whether there 

may be other records, such as tax or 

insurance records, which could satisfy 

this requirement more effectively. 

The term ‘‘fallow’’ is generally used to 

describe cultivated land taken out of 

production for a finite period of time. 

We believe it may be argued that fallow 

land is actively managed land because 

there is a clear purpose or goal for 

taking the land out of production for a 

period of time (e.g., to conserve soil 

moisture). Nonetheless, because the 

EISA language clearly identifies a 

difference between actively managed 

agricultural land and fallow agricultural 

land, we propose to define fallow to 

mean agricultural land that is 

intentionally left idle to regenerate for 

future agricultural purposes, with no 

seeding or planting, harvesting, 

mowing, or treatment during the fallow 

period. While fallow agricultural land is 

characterized by a lack of activity on the 

land, we believe that the decision to let 

land lie fallow is made deliberately and 

intentionally by a land owner or farmer 

such that there should be 

documentation of such intent. We seek 

comment on this assumption and on 

whether there are other means of 

verifying whether land was fallow, 

particularly as of December 2007. We 

also seek comment on whether we 

should specify in the regulations a time 

period after which land that is not 

actively managed for agricultural 

purposes should be considered to have 

been abandoned for agriculture (and not 

eligible for renewable biomass 

production under RFS2), as opposed to 

being left fallow. If specifying such a 

time limit is appropriate, we seek 

comment on what the time period 

should be, and if there should be a 

distinction between allowable fallow 

periods for different types of 

agricultural land. 

Finally, in order to define the term 

‘‘nonforested,’’ we first propose to 

define the term ‘‘forestland’’ as 

generally undeveloped land covering a 

minimum area of 1 acre upon which the 

predominant vegetative cover is trees, 

including land that formerly had such 

tree cover and that will be regenerated. 

We are also proposing that forestland 

would not include tree plantations. 

Under this proposal, ‘‘nonforested’’ land 

would be land that is not forestland. We 

believe this definition is sufficient to 

make distinctions between forestland 

and land that is considered nonforested 

in the field. However, we seek comment 

on whether we should incorporate into 

our definition of forestland more 

quantitative descriptors, such as a 

minimum percentage of canopy cover or 

minimum or maximum tree height, to 

help clarify what would be considered 

forestland. For example, the NRI 

definition of forestland includes a 

minimum of twenty-five percent canopy 

cover. We also seek comment on 

whether the one-acre minimum size 

designation is appropriate. 

ii. Planted Trees and Tree Residue 

The definition of renewable biomass 

in EISA includes planted trees and tree 

residue from actively managed tree 

plantations on non-federal land cleared 

at any time prior to December 19, 2007, 

including land belonging to an Indian 

tribe or an Indian individual, that is 

held in trust by the United States or 

subject to a restriction against alienation 

imposed by the United States. We 

propose to define the term ‘‘planted 

trees’’ to include not only trees that 

were established by human intervention 

such as planting saplings and artificial 

seeding, but also trees established from 

natural seeding by mature trees left 

undisturbed for such a purpose. We 

understand that, depending on the 

particular conditions at a plantation, 

certain trees in a stand may be 

harvested, while others are maintained, 

for the express purpose of naturally 

regenerating new trees. We believe that 

trees established in such a fashion, and 

which meet the conditions for planted 

trees in every other way, should not be 

24934 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

18Helms, John, ed. ‘‘The Dictionary of Forestry.’’ 

Bethesda, MD: Society of American Foresters, 2003. 

excluded from qualifying as renewable 

biomass under RFS2. 

Rather than using the term ‘‘tree 

residue,’’ we propose to use the term 

‘‘slash’’ in our regulations as a more 

descriptive, but otherwise synonymous, 

term. According to the Dictionary of 

Forestry (1998, p. 168), slash is ‘‘the 

residue, e.g., treetops and branches, left 

on the ground after logging or 

accumulating as a result of a storm, fire, 

girdling, or delimbing.’’ We believe that 

this substitution will simplify our 

regulations, since paragraph (iv) of the 

EISA definition of renewable biomass 

also uses the term ‘‘slash.’’ Furthermore, 

the term ‘‘slash’’ is a common term that 

has a specific meaning to industry. As 

noted earlier, we have attempted to 

define terms in RFS2 using existing and 

commonly understood definitions to the 

extent possible. The term ‘‘slash’’ is 

more descriptive than ‘‘tree residue,’’ 

and yet in practice means the same 

thing, so we are proposing to use it 

rather than ‘‘tree residue.’’ We also 

propose to clarify that slash can include 

tree bark and can be the result of any 

natural disaster, including flooding. 

In concert with our proposed 

definition for ‘‘planted trees,’’ we 

propose to define a ‘‘tree plantation’’ as 

a stand of no fewer than 100 planted 

trees of similar age and comprising one 

or two tree species, or an area managed 

for growth of such trees covering a 

minimum of 1 acre. Given that only 

trees from a tree plantation may be used 

as renewable biomass under RFS2, we 

believe that the definition should be 

clear and easily applied in the field. We 

recognize that this proposed definition 

is more specific than the Dictionary of 

Forestry’s definition of ‘‘tree 

plantation,’’ which is ‘‘a stand 

composed primarily of trees established 

by planting or artificial seeding.’’ We 

seek comment on all aspects of our 

proposed definition of tree plantation. 

We also propose to apply the same 

management restrictions on tree 

plantations as on agricultural land and 

to interpret the EISA language as 

requiring that to qualify for renewable 

biomass production under RFS2, a tree 

plantation must have been cleared at 

any time prior to December 19, 2007, 

and continuously actively managed 

since December 19, 2007. Similar to our 

proposal for actively managed 

agricultural land, we propose to define 

the term ‘‘actively managed’’ in the 

context of tree plantations as managed 

for a predetermined outcome as 

evidenced by any of the following: Sales 

records for planted trees or slash; 

purchasing records for seeds, seedlings, 

or other nursery stock; a written 

management plan for silvicultural 

purposes; documentation of 

participation in a silvicultural program 

sponsored by a Federal, state or local 

government agency; or documentation 

of land management in accordance with 

an agricultural or silvicultural product 

certification program. Silvicultural 

programs such as those of the Forest 

Stewardship Council, the Sustainable 

Forestry Initiative, the American Tree 

Farm System, or USDA are examples of 

the types of programs that could 

indicate actively managed tree 

plantations. 

iii. Slash and Pre-Commercial 

Thinnings 

The EISA definition of renewable 

biomass includes slash and precommercial thinnings from non-federal 

forestlands, including forestlands 

belonging to an Indian tribe or an Indian 

individual, that are held in trust by the 

United States or subject to a restriction 

against alienation imposed by the 

United States. It excludes slash and precommercial thinnings from forests or 

forestlands that are ecological 

communities with a global or State 

ranking of critically imperiled, 

imperiled, or rare pursuant to a State 

Natural Heritage Program, old growth 

forest, or late successional forest. 

As described in Sec. III.B.4.a.i of this 

preamble, our proposed definition of 

‘‘forestland’’ is generally undeveloped 

land covering a minimum area of 1 acre 

upon which the primary vegetative 

species are trees, including land that 

formerly had such tree cover and that 

will be regenerated. Also as noted in 

Sec. III.B.4.a.ii of this preamble, we 

propose to adopt the definition of slash 

listed in the Dictionary of Forestry. As 

for ‘‘pre-commercial thinnings,’’ the 

Dictionary of Forestry defines the act of 

such thinning as ‘‘the removal of trees 

not for immediate financial return but to 

reduce stocking to concentrate growth 

on the more desirable trees.’’ 18 Because 

what may now be considered precommercial may eventually be saleable 

as renewable fuel feedstock, we propose 

not to include any reference to 

‘‘financial return’’ in our definition, but 

rather to define pre-commercial 

thinnings as those trees removed from a 

stand of trees in order to reduce 

stocking to concentrate growth on more 

desirable trees. We propose to include 

diseased trees in the definition of precommercial thinnings due to the fact 

that they can threaten the integrity of an 

otherwise healthy stand of trees, and 

their removal can be viewed as reducing 

stocking to promote the growth of more 

desirable trees. We seek comment on 

whether our definition of precommercial thinnings should include a 

maximum diameter and, if so, what the 

appropriate maximum diameter should 

be. 

We understand that the State Natural 

Heritage Programs referred to in EISA 

are those comprising a network 

associated with NatureServe, a nonprofit conservation and research 

organization. The network includes 

local programs in each of the 50 United 

States, other U.S. territories and regions 

including the Navajo Nation and 

Tennessee Valley Authority, eleven 

Canadian provinces and territories, and 

eleven Latin American countries. 

Individual Natural Heritage Programs 

collect, analyze, and distribute scientific 

information about the biological 

diversity found within their 

jurisdictions. As part of their activities, 

these programs survey and apply 

NatureServe’s rankings, such as 

critically imperiled (S1), imperiled (S2), 

and rare (S3) to species and ecological 

communities within their respective 

borders. NatureServe meanwhile uses 

data gathered by these Natural Heritage 

Programs to apply its global rankings, 

such as critically imperiled (G1), 

imperiled (G2), or vulnerable (the 

equivalent of the term ‘‘rare,’’ or G3), to 

species and ecological communities 

found in multiple States or territories. 

We propose to prohibit slash and precommercial thinnings from all forest 

ecological communities with global or 

State rankings of critically imperiled, 

imperiled, or vulnerable (‘‘rare’’ in the 

case of State rankings) from being used 

for renewable fuel for which RINs may 

be generated under RFS2. We seek 

comment on our interpretation that the 

statutory language implies including 

global rankings determined by 

NatureServe, including the ranking of 

vulnerable (G3), in the land restrictions 

under RFS2 since State Natural Heritage 

Programs, which were explicitly 

referenced in EISA, do not establish 

global rankings. 

The various state-level Natural 

Heritage Programs in the U.S. and 

abroad differ in organizational 

affiliation, with some operated as 

agencies of state or provincial 

government and others residing within 

universities or non-profit organizations. 

According to the NatureServe Web site, 

‘‘consistent standards for collecting and 

managing data allow information from 

different programs to be shared and 

combined regionally, nationally, and 

internationally. The nearly 800 staff 

from across the network are experts in 

their fields, and include some of the 

most knowledgeable field biologists and 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24935 

19Old-growth forest is defined in the Dictionary 

of Forestry as ‘‘the (usually) late successional stage 

of forest development. Note: Old-growth forests are 

defined in many ways; generally, structural 

characteristics used to describe old-growth forests 

include (a) live trees: Number and minimum size 

of both seral and climax dominants, (b) canopy 

conditions: Commonly including multilayering, (c) 

snags: Minimum number of specific size, and (d) 

down logs and coarse woody debris: Minimum 

tonnage and numbers of pieces of specific size. 

Note: Old-growth forests generally contain trees that 

are large for their species and site and sometimes 

decadent (overmature) with broken tops, often a 

variety of trees sizes, large snags and logs, and a 

developed and often patchy understory * * *.’’ 

20See Cohen, Jack. ‘‘Reducing the Wildland Fire 

Threat to Homes: Where and How Much?’’ USDA 

Forest Service Gen.Tech.Rep. PSW–GTR–173. 1999. 

See also U.S. Federal Emergency Management 

Agency (FEMA) Web site http://www.fema.gov/ 

hazard/wildfire/index.shtm. 

conservation planners in their regions.’’ 

Different Natural Heritage Programs 

have different processes for initiating 

and performing surveys of ecological 

communities. In many cases, the 

programs respond to requests for 

environmental reviews or surveys from 

parties interested in specific locations, 

oftentimes for a fee. They do not make 

available for public consumption 

detailed information on the location of 

a ranked ecological community in some 

cases to protect the communities 

themselves and in other cases to protect 

private property interests. Additionally, 

the datasets maintained by different 

Natural Heritage Programs may not 

completely represent all of the 

vulnerable ecological communities in 

their respective States or territories 

simply due to the fact that surveys have 

not been performed for all areas. 

NatureServe, however, interacts with 

each of the State Natural Heritage 

Programs to update their central 

database to include each State program’s 

ecological community rankings. We 

propose to use data compiled by 

NatureServe and published in a special 

report to identify ‘‘ecologically sensitive 

forestland.’’ The report would list all 

forest ecological communities in the 

U.S. with a global ranking of G1, G2, or 

G3, or with a State ranking of S1, S2, or 

S3, and would include descriptions of 

the key geographic and biologic 

attributes of the referenced ecological 

community. The document would be 

incorporated by reference into the 

definition of renewable biomass in the 

final RFS2 regulations, and the effect 

would be to identify specific ecological 

communities from which slash and precommercial thinnings could not be used 

as feedstock for the production of 

renewable fuel that would qualify for 

RINs under RFS2. In the future, it may 

be necessary to update this list as 

appropriate through notice and 

comment rulemaking. 

We will place a draft version of this 

document in the docket for the 

proposed rule as soon as it is available. 

EPA solicits comment both on this 

general incorporation-by-reference 

approach and on each individual listing 

in the document. We also seek comment 

on whether EPA should include in the 

document forest ecological communities 

outside of the 50 United States (such as 

in Canada or Latin American countries) 

that have natural heritage rankings of 

G1, G2, or G3 or S1, S2, or S3. In 

addition, we request comment on other 

ways that EPA may be able to provide 

the protections that Congress intended 

for important ecological communities 

with state-level rankings pursuant to a 

State Natural Heritage Program. 

To complete the definition of 

‘‘ecologically sensitive forestland,’’ we 

propose to include old growth and late 

successional forestland which is 

characterized by trees at least 200 years 

old.19 We seek comment on this 

definition, including the proposed 200- 

year tree age, on whether we should 

specify a process for determining when 

a forest is ‘‘characterized by’’ trees of 

this or another age, and on other ways 

to identify old growth or late 

successional forestland. 

iv. Biomass Obtained From Certain 

Areas at Risk From Wildfire 

The EISA definition of renewable 

biomass includes biomass obtained from 

the immediate vicinity of buildings and 

other areas regularly occupied by 

people, or of public infrastructure, at 

risk from wildfire. We propose to clarify 

in the regulations that ‘‘biomass’’ is 

organic matter that is available on a 

renewable or recurring basis, and that it 

must be obtained from within 200 feet 

of buildings, campgrounds, and other 

areas regularly occupied by people, or of 

public infrastructure, such as utility 

corridors, bridges, and roadways, in 

areas at risk of wildfire. We propose to 

define ‘‘areas at risk of wildfire’’ as areas 

located within—or within one mile of— 

forestland, tree plantations, or any other 

generally undeveloped tract of land that 

is at least one acre in size with 

substantial vegetative cover. 

It is our understanding that 100 to 200 

feet is the minimum distance 

recommended for clearing trees and 

brush away from homes and other 

property in certain wildfire-prone areas, 

depending on slope and vegetation.20

We propose that under RFS2, the term 

‘‘immediate vicinity’’ would mean 

within 200 feet of a given structure or 

area, but we seek comment on the 

appropriateness of limiting the distance 

to within 100 feet. 

A great deal of work has been done to 

identify communities and areas on the 

landscape in the vicinity of public lands 

that are at risk of wildfire by States in 

cooperation and consultation with the 

U.S. Forest Service, Bureau of Land 

Management, and other federal, State, 

and local agencies and tribes. In order 

to take advantage of this work, we seek 

comment on two possible 

implementation alternatives. The first 

alternative would incorporate into our 

definition of ‘‘areas at risk of wildfire’’ 

any communities identified as 

‘‘communities at risk’’ through a process 

defined within the ‘‘Field Guidance— 

Identifying and Prioritizing 

Communities at Risk’’ (National 

Association of State Foresters, June 

2003) and covered by a community 

wildfire protection plan (CWPP) 

developed in accordance with 

‘‘Preparing a Community Wildfire 

Protection Plan—A Handbook for 

Wildland-Urban Interface 

Communities’’ (Society of American 

Foresters, March 2004) and certified by 

a State Forester or equivalent. We 

believe that it may make sense to 

include communities with CWPPs in 

the definition of ‘‘areas at risk of 

wildfire’’ since they represent specific 

areas around the U.S. that are identified 

and agreed upon through a public 

process that includes local and state 

representatives, federal agencies, and 

stakeholders. Additionally, CWPP 

guidelines indicate that normally three 

entities must mutually agree to the 

contents of the CWPPs: The applicable 

local government, the local fire 

department or departments, and the 

state entity responsible for forest 

management (State Forester or 

equivalent). As of June 2008, there were 

roughly 52,000 total ‘‘communities at 

risk’’ and 5,000 ‘‘communities at risk’’ 

covered by a CWPP. 

We seek comment on incorporating by 

reference into the final RFS2 regulations 

a list of ‘‘communities at risk’’ with an 

approved CWPP. Similar to the 

document proposed for Natural Heritage 

Rankings, this document would be 

incorporated by reference into the 

definition of ‘‘areas at risk of wildfire’’ 

in the final RFS2 regulations. Because 

this list does not currently exist, EPA 

would be required to seek data from 

each State in order to assemble the 

document. The effect of this 

incorporation by reference would be to 

identify specific areas in the U.S. at risk 

of wildfire and from which biomass 

obtained from the immediate vicinity of 

buildings and other areas regularly 

occupied by people, or of public 

infrastructure, could be easily identified 

24936 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

21See http://silvis.forest.wisc.edu/projects/ 

US_WUI_2000.asp. 

and documented as renewable biomass. 

In the future, it may be necessary to 

update this list as appropriate through 

notice and comment rulemaking. 

The second implementation approach 

on which we seek comment would 

incorporate into our definition of ‘‘areas 

at risk of wildfire’’ any areas identified 

as wildland urban interface (WUI) land, 

or land in which houses meet wildland 

vegetation or are mixed with vegetation. 

The concept of the WUI was established 

as part of the Healthy Forests 

Restoration Act (Pub. L. 108–148) which 

provided a means for prioritizing, 

planning, and executing hazardous fuels 

reduction projects on federal lands. 

SILVIS Lab, in the Department of Forest 

Ecology and Management and the 

University of Wisconsin, Madison, has, 

with funding provided by the U.S. 

Forest Service, mapped WUI lands 

based on data from the 2000 U.S. 

Census and U.S. Geological Survey 

National Land Cover Data.21 We seek 

comment on whether and how best to 

make use of this WUI map and data to 

help implement the land restrictions for 

biomass obtained from areas at risk of 

wildfire under RFS2. 

b. Issues Related to Implementation and 

Enforceability 

Incorporating the new definition of 

renewable biomass into the RFS2 

program raises issues that we did not 

have to consider when designing the 

RFS1 program. Under RFS1, the source 

of a renewable fuel feedstock was not a 

central concern, and it was a relatively 

straightforward matter to require all fuel 

made from specified renewable 

feedstocks to be assigned RINs. 

However, with the terms ‘‘renewable 

fuel’’ and ‘‘renewable biomass’’ being 

defined differently under EISA, we must 

consider potential issues related to 

implementation and enforcement to 

ensure that renewable fuel for which 

RINs are generated is produced from 

qualifying renewable biomass. 

Our proposed approach to the 

treatment of renewable biomass under 

RFS2 is intended to define the 

conditions under which RINs can be 

generated as well as the conditions 

under which renewable fuel can be 

produced or imported without RINs. 

Both of these areas are described in 

more detail below. 

i. Ensuring That RINs Are Generated 

Only for Fuels Made From Renewable 

Biomass 

The effect of adding EISA’s definition 

of renewable biomass to the RFS 

program is to ensure that renewable 

fuels are only allowed to participate in 

the program if the feedstocks from 

which they were made come from 

certain types of land. In the context of 

our regulatory program, this means that 

RINs could only be generated if it can 

be established that the feedstock from 

which the fuel was made came from 

these types of lands. Otherwise, no RINs 

could be generated to represent the 

renewable fuel produced or imported. 

We have considered the possibility 

that land restrictions contained within 

the definition of renewable biomass may 

not, in practice, result in a significant 

change in agricultural practices. For 

example, a farmer wishing to expand his 

production by cutting forested land 

could grow feedstock for renewable fuel 

on his existing agricultural land and 

move production for food, animal feed, 

and fiber production to newly cultivated 

land. While the EISA language is fairly 

clear about what lands may be used for 

harvesting renewable fuel feedstocks, it 

does not specifically address the 

potential for switching non-feedstock 

crops to new lands. Our proposed 

options recognize the potential for this 

behavior but do not attempt to prohibit 

it as we believe doing so would be 

beyond our mandate under EISA. EPA 

believes that Congress would have 

specifically directed EPA to regulate 

this practice if they intended EPA to do 

so. 

Another major issue we have 

considered is the treatment of 

domestically produced renewable fuel 

feedstocks versus imported feedstocks 

and imported renewable fuel, since the 

new EISA language does not distinguish 

between domestic renewable fuel 

feedstocks and renewable fuel and 

feedstocks that come from abroad. 

Under RFS1, RINs must be generated for 

imported renewable fuel by the 

renewable fuel importer. Foreign 

renewable fuel producers may not 

participate as producers in the program 

(i.e., may not generate RINs for their 

fuel) unless they produce cellulosic 

biomass or waste-derived ethanol and 

register with EPA. Because RFS1 does 

not define renewable fuel by its source, 

assigning RINs to imported renewable 

fuel under RFS1 is a straightforward 

responsibility of the importer. 

However, under RFS2, ensuring that 

the feedstock used to produce imported 

renewable fuel meets the definition of 

renewable biomass presents additional 

challenges to designing a program that 

can apply to both domestic and 

imported renewable fuel. The options 

contained in today’s proposal attempt to 

address this additional constraint, as 

discussed in Section III.B.4.d of this 

preamble. 

ii. Ensuring That RINs Are Generated for 

All Qualifying Renewable Fuel 

Under RFS1, virtually all renewable 

fuel is required to be assigned a RIN by 

the producer or importer. This 

requirement was developed and 

finalized in the RFS1 rulemaking in 

order to address stakeholder concerns, 

particularly from obligated parties, that 

the number of available RINs should 

reflect the total volume of renewable 

fuel used in the transportation sector in 

the U.S. and facilitate program 

compliance. The only circumstances 

under which a batch of fuel is not 

assigned a RIN in RFS1 is if the 

feedstock used to produce the fuel is not 

among those listed in the regulatory 

definition of renewable fuel at 

§ 80.1101(d), the producer or importer 

of the fuel produces or imports less than 

10,000 gallons per year, or the fuel is 

produced and used for off-road or other 

non-motor vehicle purposes. As a result, 

we believe that almost all renewable 

fuel produced or imported into the U.S. 

is assigned RINs under the RFS1 

program, and thus the number of RINs 

available to obligated parties represents 

as accurately as possible the volume of 

renewable fuel being used in the U.S. 

transportation sector. 

EISA has dramatically increased the 

mandated volumes of renewable fuel 

that obligated parties must ensure are 

produced and used in the U.S. At the 

same time, EISA makes it more difficult 

for renewable fuel producers to 

demonstrate that they have fuel that 

qualifies for RIN generation by 

restricting qualifying renewable fuel to 

that made from ‘‘renewable biomass,’’ 

defined to include restrictions on the 

types of land from which feedstocks 

may be harvested, as discussed in this 

section. The inclusion of such land 

restrictions under RFS2 may mean that, 

in some situations, a renewable fuel 

producer would prefer to forgo the 

benefits of RIN generation to avoid the 

cost and difficulty of ensuring that its 

feedstocks qualify for RIN generation. If 

a sufficient number of renewable fuel 

producers acted in this way, it could 

lead to a situation in which not all 

qualifying fuel is assigned RINs, thus 

resulting in a short RIN market that 

could force obligated parties into noncompliance. Another possible outcome 

would be that the demand for and price 

of RINs would increase significantly, 

making compliance by obligated parties 

more costly and difficult than necessary 

and raising prices for consumers. 

In order to avoid situations in which 

obligated parties cannot comply with 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24937 

their annual RVOs and the volume 

mandates in EISA are not met, or 

instances where the requirements are 

met but at an inflated price, we believe 

that our proposal should ensure that 

RINs are generated for all fuel made 

from feedstock that meets the definition 

of renewable biomass and which meets 

the GHG emissions reduction thresholds 

set out in EISA. This would require 

eliminating any incentive for renewable 

fuel producers to avoid ascertaining 

where their feedstocks come from. As 

described in Section III.B.4.d below, we 

propose to require a demonstration of 

the type of land used to produce any 

feedstock used in the production of 

renewable fuel, regardless of whether 

RINs are generated or not, and to require 

that RINs be generated for all qualifying 

fuel. 

However, we also seek comment on 

an alternative approach wherein a 

renewable fuel producer would not be 

required to make any demonstration 

with regard to the origin of feedstocks 

used in fuel production if the fuel 

producer were not generating RINs. In 

this situation, we would rely on the 

price of RINs in the market to encourage 

renewable fuel producers to generate 

RINs where possible. This approach 

would have the advantage of lessening 

the regulatory burden for renewable fuel 

producers using feedstock that is not 

renewable biomass, and would 

generally simplify the regulations 

relating to implementation of the 

renewable biomass definition. The 

disadvantage to this approach, as 

discussed above, would be the increased 

potential for a RIN shortage caused by 

renewable fuel producers choosing not 

to generate RINs for qualifying 

renewable fuel and a concurrent 

increase in the price of RINs that do 

exist. Under such circumstances, it is 

likely that some obligated parties could 

not acquire sufficient RINs for 

compliance purposes, while others 

could comply but at an inflated cost. 

A further step that we could take to 

streamline not just the implementation 

of the renewable biomass definition, but 

also the tracking and trading of RINs, 

would be to remove the restriction 

established under the RFS1 rule 

requiring that RINs be assigned to 

batches of renewable fuel and 

transferred with those batches. Instead, 

renewable fuel producers could sell 

RINs (with a K code of 2 rather than 1) 

separately from volumes of renewable 

fuel. While this alternative approach 

could potentially place obligated parties 

at greater risk of market manipulation 

by renewable fuel producers, it could 

also provide a greater incentive for 

producers to demonstrate that the 

renewable biomass definition has been 

met for their feedstocks. That is, by 

having the flexibility to sell RINs 

independent from volume, producers 

could potentially command higher 

prices for those RINs. This would make 

RINS more valuable to them, and 

provide an incentive to generate as 

many RINs as possible. As a result, 

producers would be motivated to 

demonstrate that their feedstocks meet 

the renewable biomass definition. 

However, this approach could also 

increase compliance costs for obligated 

parties. For further discussion of this 

approach, see Section III.H.4. 

c. Review of Existing Programs 

i. USDA Programs 

To inform our approach for designing 

an implementation scheme for the 

renewable biomass land restrictions 

under RFS2, we reviewed a number of 

programs and models that track, certify, 

or verify agricultural and silvicultural 

products or land use in the U.S. and 

abroad. First we looked at several 

existing programs administered by 

USDA that involve data collection from 

agricultural land owners, farmers, and 

forest owners. However, while USDA 

obtains and maintains valuable data 

from agricultural land owners, 

producers, and forest owners for 

assessing the status of agricultural land, 

forest land, and other types of land that 

could be used for renewable fuel 

feedstock production, Section 1619 of 

the Food, Conservation, and Energy Act 

of 2008 (the 2008 Farm Bill) and 

policies of certain USDA agencies 

significantly limit EPA’s ability to 

access such data in a timely and 

meaningful way. Given that agricultural 

land owners, producers, and forest 

owners already report a great deal of 

information to USDA, having access to 

such information could enable EPA to 

avoid having to require duplicative 

reporting or recordkeeping and thereby 

minimize any burden that RFS2 may 

place on parties in the renewable fuel 

feedstock supply chain, from feedstock 

producer to renewable fuel producer, 

while still allowing us to ensure that the 

land restrictions on renewable biomass 

production are adhered to. We request 

comment on how EPA could acquire the 

type of information submitted by parties 

such as agricultural land owners, 

producers, and forest owners to USDA 

agencies in order to aid in administering 

RFS2. Having access to such 

information could be valuable to EPA in 

informing our enforcement actions. 

ii. Third-Party Programs 

To inform our options for how we 

might verify and track renewable 

biomass, we also explored nongovernmental, third-party verification 

programs used for certifying and 

tracking agricultural and forest products 

from point of origin to point of use both 

within the U.S. and outside the U.S. The 

United Kingdom and the EU are looking 

to such third-party verification 

programs to implement the 

sustainability provisions of their 

biofuels programs. There is no thirdparty organization that certifies 

agricultural land, managed tree 

plantations, and forests; rather, each 

generally focuses on one area. Due to 

this constraint, we examined third party 

organizations that certify specific types 

of biomass from croplands and 

organizations that certify forest lands. 

We examined third-party 

organizations that focus on a particular 

type of feedstock used for renewable 

fuel production, including the 

Roundtable on Sustainable Palm Oil and 

the Basel Criteria for Responsible Soy 

Production. These initiatives have 

outlined traceable certification programs 

for industry to follow. Two other 

cooperative organizations whose 

primary concern is renewable fuel 

production from biomass are the 

Roundtable on Sustainable Biofuels 

(RSB) and the Better Sugarcane 

Initiative (BSI). At present, the RSB and 

BSI are still in their developmental 

stages and do not have fully developed 

certification processes. 

We also examined the work of the 

international Soy Working Group, 

comprised of representatives from 

industry, the Brazilian government, and 

international non-governmental 

organizations (NGOs), which recently 

announced a one-year extension of a 

moratorium on the use of soy harvested 

from recently deforested lands in the 

Brazilian Amazon. This moratorium is 

the result of a negotiated voluntary 

agreement through which companies 

that purchase Brazilian soy work with 

their suppliers to ensure that they 

source their soy from farms cultivated 

prior to August 2006. The Brazilian 

Association of Vegetable Oil Industries 

(ABIOVE) and Brazil’s National 

Association of Grain Exporters (ANEC) 

have used aerial photography to identify 

whether any newly deforested areas 

were used to grow soy, and Greenpeace, 

one of the NGOs involved in the 

agreement, uses satellite imagery and 

aerial photography to perform spot 

checks for enforcement purposes. 

Another new example of a renewable 

fuel feedstock verification system is the 

24938 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

22Forest acreage taken from USDA Economic 

Research Service, Major uses of Land in the United 

States, 2002, Economic Information Bulletin No. 

(EIB–14), May 2006. 

23FSC certified acreage taken from FSC–US, 

Prospectus, 2005. 

Verified Sustainable Ethanol initiative, 

which established a series of criteria for 

ethanol produced in Brazil and sold to 

Swedish ethanol importer SEKAB. The 

Brazilian sugarcane ethanol industry 

trade association, UNICA, its member 

companies, and SEKAB established the 

criteria to promote environmental and 

social sustainability of sugarcane 

ethanol exported to Sweden. The 

agreement is between companies, and it 

relies on a third-party auditor to inspect 

Brazilian feedstock and ethanol 

production facilities to verify 

compliance with the criteria. 

We also examined third-party 

organizations that specialize in 

certifying sustainable forest lands. The 

Sustainable Agriculture Network (SAN), 

through the Rainforest Alliance, 

provides comprehensive certification of 

wooded areas used for commercial 

development through sustainable 

processes in the United States and Latin 

American countries. The SAN certifies 

approximately 10 million acres of land 

worldwide, with minimal agricultural 

land certified in the U.S.22

We examined the certification process 

of the Forest Stewardship Council (FSC) 

because of their international 

recognition for certifying sustainable 

forests and their recordkeeping 

requirement for ‘‘chain of supply’’ 

certification for products. The FSC 

certifies 22 million acres of land in the 

U.S. according to certification standards 

designed for nine separate regions 

within the U.S., and it provides an 

example for chain-of-custody and 

product segregation requirements.23

Finally, we examined the American 

Tree Farm program and Sustainable 

Forestry Initiative (SFI). 

The criteria used to certify 

participants through third-party 

verification systems are overall more 

comprehensive and generally more 

stringent than the land restrictions 

contained within the definition of 

renewable biomass. However, three 

issues emerged through our 

investigation of these existing thirdparty verification systems that would 

make it difficult to adopt or incorporate 

any one of them into our regulations for 

the land restriction provisions under 

EISA. First, as previously noted, many 

of these third-party certifiers are limited 

in the scope of products that they 

certify. Second, the acreage of 

agricultural land or actively managed 

tree plantations certified through third 

parties in the U.S. covers only a small 

portion of the total available land and 

forests estimated to qualify for 

renewable biomass production under 

the EISA definition. Third, none of the 

existing third-party systems had 

definitions or criteria that perfectly 

matched the land use definitions and 

restrictions contained in the EISA 

definition of renewable biomass. Thus, 

we have determined that at this time we 

cannot rely on any existing third-party 

verification program solely to 

implement the land restrictions on 

renewable biomass under RFS2. We 

believe there is potential benefit in 

utilizing third-party verification 

programs if these issues can be 

addressed, and in the following section 

we offer one possible scenario as an 

implementation alternative. 

Nonetheless, we seek comment on our 

conclusion that there are currently no 

appropriate third-party verification 

systems for renewable biomass that 

could be adopted under RFS2. We 

further seek comment on whether any 

existing program or combination of 

programs would be able to meet the 

definitions and adopt the land 

restriction criteria proposed for RFS2 to 

assist industry in meeting their 

obligations under this proposed 

program. 

d. Approaches for Domestic Renewable 

Fuel 

Consistent with RFS1, renewable fuel 

producers would be responsible for 

generating RINs under RFS2. In order to 

make a determination whether or not 

their fuel is eligible for RINs, renewable 

fuel producers would need to have at 

least basic information about the origin 

of their feedstock. The following 

approaches for implementing the land 

restrictions on renewable biomass 

contained in EISA illustrate the variety 

of ways that renewable fuel feedstocks 

could be handled under RFS2. These 

options are presented singly, but we 

seek comment on how they might be 

combined to create the most 

appropriate, practical, and enforceable 

implementation scheme for renewable 

biomass under RFS2. 

One approach for ensuring that 

producers generate RINs properly would 

be for EPA to require that renewable 

fuel producers obtain documentation 

about their feedstocks from their 

feedstock supplier(s) and take the 

measures necessary to ensure that they 

know the source of their feedstocks and 

can demonstrate to EPA that they have 

complied with the EISA definition of 

renewable biomass. Under this 

approach, EPA would require renewable 

fuel producers who generate RINs to 

certify on their renewable fuel 

production reports that the feedstock 

used for each renewable fuel batch 

meets the definition of renewable 

biomass. We would require renewable 

fuel producers to maintain sufficient 

records to support these claims. 

Specifically, renewable fuel producers 

who use planted crops or crop residue 

from existing agricultural land, or who 

use planted trees or slash from actively 

managed tree plantations, would be 

required to have copies of their 

feedstock producers’ written records 

that serve as evidence of land being 

actively managed (or fallow, in the case 

of agricultural land) since December 

2007, such as sales records for planted 

crops or trees, livestock, crop residue, or 

slash; a written management plan for 

agricultural or silvicultural purposes; or, 

documentation of participation in an 

agricultural or silvicultural program 

sponsored by a Federal, state or local 

government agency. In the case of all 

other biomass, we would require 

renewable fuel producers to have, at a 

minimum, written certification from 

their feedstock supplier that the 

feedstock qualifies as renewable 

biomass. We seek comment on whether 

we should also require renewable fuel 

producers that use slash and precommercial thinnings from non-federal 

forestland and biomass from areas at 

risk of wildfire to maintain additional 

records to support the claim that these 

feedstocks meet the definition of 

renewable biomass. These records could 

include sworn statements from licensed 

or registered foresters, contracts for tree 

or slash removal or documentation of 

participation in a fire mitigation 

program. We seek comment on other 

methods of verifying renewable fuel 

producers’ claims that feedstocks 

qualify for these categories of renewable 

biomass. A review of such records 

would become part of the producer’s 

annual attest engagement, the annual 

audit of their records by an independent 

third party (see Section IV.A for a full 

discussion of attest engagement 

requirements). 

A renewable fuel producer would 

only be permitted to produce and sell 

renewable fuel without RINs if he 

demonstrates that the feedstocks used to 

produce his fuel do not meet the 

definition of renewable biomass. This 

approach would ensure that renewable 

fuel producers could not avoid the 

generation of RINs simply by failing to 

make a demonstration regarding the 

land used to produce their feedstocks. 

Thus, renewable fuel producers would 

be required to keep records of their 

feedstock source(s), regardless of 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24939 

whether RINs were generated or not. At 

a minimum, renewable fuel producers 

who do not generate RINs would need 

to have certification from their feedstock 

supplier that their feedstock does not 

meet the definition of renewable 

biomass. In the event that some portion 

of a load of feedstock does meet the 

definition of renewable biomass and 

some portion does not, the renewable 

fuel producer would need to maintain 

documentation from their supplier that 

states the percentage of each portion. 

All of these records would be included 

as part of the renewable fuel producer’s 

annual attest engagement. The 

renewable fuel producer would also 

indicate on his renewable fuel 

production report that he did not 

generate RINs for fuel made from 

feedstock that did not meet the 

definition of renewable biomass. 

Some stakeholders have expressed 

concern about EPA specifying the 

records that a renewable fuel producer 

must obtain from their feedstock 

supplier. We therefore seek comment on 

an approach that would require 

renewable fuel producers to certify on 

their renewable fuel production reports 

that their feedstock either met or did not 

meet the definition of renewable 

biomass and would require producers to 

maintain sufficient records to support 

their claims, but would stop short of 

specifying what those records would 

have to include. We anticipate that a 

large portion of feedstocks that qualify 

as renewable biomass will be obtained 

from existing agricultural land or 

actively managed tree plantations, for 

which, by definition, documentation 

already exists. We believe that, in most 

other cases, feedstock producers will 

have or will be able to create other 

forms of documentation that could be 

provided to renewable fuel producers in 

order to provide adequate assurance that 

the feedstock in question meets the 

definition of renewable biomass. As 

described above, there are many existing 

programs, such as those administered by 

USDA and independent third-party 

certifiers, that could be useful to verify 

that feedstock from certain land 

qualifies as renewable biomass. 

We anticipate that these selfcertification approaches would result in 

renewable fuel producers amending 

their contracts and altering their supply 

chain interactions to satisfy their need 

for documented assurance and proof 

about their feedstock’s origins. 

Enforcement under either of these 

approaches would rely in part on EPA’s 

review of renewable fuel production 

reports and attest engagements of 

renewable fuel producers’ records. EPA 

would also consult other data sources, 

including any data made available by 

USDA, and could conduct site visits or 

inspections of feedstock producers’ and 

suppliers’ facilities. We seek comment 

on the feasibility and practical 

limitations of EPA working with 

publicly available USDA data to keep 

track of significant land use changes in 

the U.S. and around the world and to 

note general increases in feedstock 

supplier productivity that might signal 

cultivation of new agricultural land for 

renewable fuel feedstock production. 

Either of these approaches would 

easily fold into existing and newly 

proposed registration, recordkeeping, 

reporting, and attest engagement 

procedures. They would also place the 

burden of implementation and 

enforcement on renewable fuel 

producers rather than bringing feedstock 

producers and suppliers directly under 

EPA regulation. In this way, they would 

minimize the number of regulated 

parties under RFS2. They would also 

allow, to varying degree, the renewable 

fuel industry to determine the most 

efficient means of verifying and tracking 

feedstocks from the point of production 

to the point of consumption, thereby 

minimizing any additional cost and 

administrative burden created by the 

EISA definition of renewable biomass. 

Another alternative would be for EPA 

to establish a chain-of-custody tracking 

system from feedstock producer to 

renewable fuel producer through which 

renewable fuel producers would obtain 

information regarding the lands where 

their feedstocks were produced. This 

information would accompany each 

transfer of custody of the feedstock until 

the feedstock reaches the renewable fuel 

producer. Renewable fuel feedstock 

producers, suppliers and handlers 

would not have any reporting 

obligations. EPA would, however, 

require all feedstock producers, 

suppliers, and handlers to maintain as 

records these chain-of-custody 

documents for all biomass intended to 

be used as a renewable fuel feedstock. 

Renewable fuel producers would also be 

required to maintain these chain-ofcustody tracking documents in their 

records and would have to include them 

as part of their records presented during 

their annual attest engagement. 

An additional alternative would be for 

EPA to require renewable fuel producers 

to set up and administer a quality 

assurance program that would create an 

additional level of rigor in the 

implementation scheme for the EISA 

land restrictions on renewable biomass. 

The quality assurance program could 

include (1) an unannounced 

independent third party inspection of 

the renewable feedstock producer’s 

facility at least once per quarter or once 

every 15 deliveries, whichever is more 

frequent, (2) an unannounced 

independent third party inspection of 

each intermediary facility that stores 

renewable fuel feedstock received by the 

renewable fuel producer at least once 

per quarter, and (3) on each occasion 

when the independent third party 

inspection reveals noncompliance, the 

renewable fuel producer must (a) 

conduct an investigation to determine 

the proper number of RINs that should 

have been generated for a volume of fuel 

and either generate or retire an equal 

number of RINs, depending on whether 

the fuel’s feedstock did or did not meet 

the definition of renewable biomass, (b) 

conduct a root cause analysis of the 

violation, and (c) refuse to accept or 

process feedstock from the renewable 

fuel feedstock producer unless or until 

the feedstock producer takes 

appropriate corrective action to prevent 

future violations. 

This alternative could provide a 

partial affirmative defense either for 

renewable producers that illegally 

generate RINs for fuel made from 

feedstocks that do not qualify as 

renewable biomass or for renewable fuel 

producers who do not generate enough 

RINs for fuel made from feedstocks that 

do qualify as renewable biomass. In 

either case, the producers must 

demonstrate that the violation was 

caused by a feedstock producer or 

supplier and not themselves; that the 

commercial documents (e.g., bills of 

lading) received with the feedstock 

indicated that the feedstock either met 

(in the case that RINs were generated 

illegally) or did not meet (in the case 

that an inadequate number of RINs were 

generated) the land restrictions for 

renewable biomass, and that they met 

EPA’s quality assurance program 

requirements. A renewable fuel 

producer that generates RINs for fuel 

made from a feedstock that does not 

meet the definition of renewable 

biomass, but that qualifies for the partial 

affirmative defense, would still have to 

retire a number of RINs equal to the 

illegally generated RINs. Likewise, a 

renewable fuel producer that does not 

generate sufficient RINs for fuel made 

from a feedstock that does meet the 

definition of renewable biomass, but 

that qualifies for the partial affirmative 

defense, would have to generate enough 

RINs to make up the difference. 

However, in neither case would they be 

subject to civil penalties. 

As yet another alternative approach, 

EPA could bring together renewable fuel 

producers and renewable fuel feedstock 

producers and suppliers to develop an 

industry-wide quality assurance 

24940 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

program for the renewable fuel 

production supply chain, following the 

model of the successful Reformulated 

Gasoline Survey Association. We 

believe that this alternative could be 

less costly than if each individual 

renewable fuel producer were to create 

their own quality assurance program, 

and it would add a quality assurance 

element to RFS2 while creating the 

possibility for a partial affirmative 

defense for renewable fuel producers 

and feedstock producers and suppliers. 

The program would be carried out by 

an independent surveyor funded by 

industry and consist of a nationwide 

verification program for renewable fuel 

producers and renewable feedstock 

producers and handlers designed to 

provide independent oversight of the 

feedstock designations and handling 

processes that are required to determine 

if a feedstock meets the definition of 

renewable biomass. Under this 

alternative, a renewable fuel producer 

and its renewable feedstock suppliers 

and handlers would have to participate 

in the funding of an organization which 

arranges to have an independent 

surveyor conduct a program of 

compliance surveys. Compliance 

surveys would be carried out by an 

independent surveyor pursuant to a 

detailed survey plan submitted to EPA 

for approval by November 1 of the year 

preceding the year in which the 

alternative quality assurance sampling 

and testing program would be 

implemented. The survey plan would 

include a methodology for determining 

when the survey samples would be 

collected, the locations of the surveys, 

the number of inspections to be 

included in the survey, and any other 

elements that EPA determines are 

necessary to achieve the same level of 

quality assurance as the requirement 

included in the RFS2 regulations at the 

time. 

Under this alternative, the 

independent surveyor would be 

required to visit renewable feedstock 

producers and suppliers to determine if 

they are properly designating their 

product and adhering to adequate chain 

of custody requirements. This 

nationwide sampling program would be 

designed to ensure even coverage of 

renewable feedstock producers and 

suppliers. The surveyor would generate 

and report the results of the surveys to 

EPA each calendar quarter. In addition, 

where the survey finds improper 

designations or handling, the liable 

parties would be responsible for 

identifying and addressing the root 

cause of the violation to prevent future 

violations. When a violation is detected, 

the renewable fuel producer that 

participates in the consortium would be 

deemed to have met the quality 

assurance criteria for a partial 

affirmative defense. If the renewable 

fuel producer met the other applicable 

criteria, he would have to take 

corrective action to retire or generate the 

appropriate number of RINs depending 

on the violation, but he would not be 

subject to civil penalties. 

Some stakeholders have suggested 

that EPA take advantage of existing 

satellite and aerial imagery and 

mapping software and tools to 

implement the renewable biomass 

provisions of EISA. One way to do so 

would be for EPA to develop a 

renewable fuel mapping Web site to 

assist regulated parties in meeting their 

obligation to identify the location of 

land where renewable fuel feedstocks 

are produced. Such a Web site could 

include an interactive map that would 

allow renewable feedstock producers to 

trace the boundaries of their property 

and create an electronic file with 

information regarding the land where 

their renewable fuel feedstocks were 

produced, such as a code that identifies 

the plot of land. This would allow the 

feedstock producer to provide 

information, such as a standard land ID 

code, on all bills of lading or other 

commercial documents that identify the 

type and quantity of feedstock being 

delivered to the renewable fuel 

producer. Renewable fuel producers 

could then make a determination 

regarding whether or not the renewable 

fuel feedstock that they use meets the 

definition of renewable biomass, and is 

therefore eligible or not for RIN 

generation. 

Feedstock producers would not 

necessarily be required to use this 

Internet-based tool to identify the 

location where renewable fuel 

feedstocks are produced, since many 

feedstock producers already participate 

in various government or insurance 

programs that have required them to 

map the location of their fields. But the 

map would enable renewable fuel 

producers to verify the accuracy of these 

descriptions and report these locations 

to EPA using the interactive mapping 

tool on EPA’s Web site. EPA specifically 

solicits comment on the practicability of 

constructing an accurate map from 

existing data sources. 

As noted above, EPA recognizes that 

land restrictions contained within the 

definition of renewable biomass may 

not, in practice, result in a significant 

change in agricultural practices. EPA 

also recognizes that the implementation 

options described in this proposal could 

impose costs and constraints on existing 

storage, transportation, and delivery 

systems for feedstocks, in particular for 

corn and soybeans in the U.S. We 

therefore seek comment on a 

stakeholder suggestion to establish a 

baseline level of production of biomass 

feedstocks such that reporting and 

recordkeeping requirements would be 

triggered only when the baseline 

production levels of feedstocks used for 

biofuels were exceeded. Such an 

approach would avoid imposing a new 

recordkeeping burden on the industry as 

long as biofuels demand is met with 

existing feedstock production. We seek 

comment on this alternative, including 

how to set the baseline production 

levels and information on appropriate 

data sources in the U.S. and in other 

countries that produce feedstocks that 

could be used for renewable fuel 

production, and on how to track 

whether the feedstock use for biofuels 

production has exceeded baseline 

production levels. We also solicit 

comment on whether this approach 

could be applied to all types of 

feedstocks on which EISA places land 

restrictions, or if it would only be 

appropriate for traditional agricultural 

crops such as corn, soybeans, and 

sugarcane for which historical acreage 

data exists both domestically and 

internationally. 

EPA acknowledges that under this 

alternative, while there could be a net 

increase in lands being cultivated for a 

particular crop, we would presume that 

increases in cultivation would be used 

to meet non-biofuels related feedstock 

demand. We also acknowledge that such 

an approach would be difficult to 

enforce because data that could indicate 

that baseline production levels were 

exceeded in a given year would likely 

be delayed by many months, such that 

the recordkeeping requirements for 

renewable fuel producers would also be 

delayed. During the interim period, 

renewable fuel producers would have 

generated RINs for fuel that did not 

qualify for credit under the program, 

and any remedial steps to invalidate 

such RINs after the fact could be costly 

and burdensome to all parties in the 

supply chain. Nonetheless, we seek 

comment on the approach as described 

above. 

We seek comment on all of these 

approaches and what combination of 

these approaches would be the most 

appropriate, enforceable, and practical 

for ensuring that the land restrictions on 

renewable biomass contained in EISA 

are implemented under RFS2. We also 

seek comment on whether there are 

other possible approaches that would be 

superior to those we have described 

above. We also note that we intend to 

monitor RIN generation and the trends 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24941 

in renewable fuel feedstock sources as 

RFS2 implementation gets underway, 

and that we may make changes to the 

approach we adopt in the final RFS2 

regulations if renewable fuel feedstock 

production conditions change or if new, 

better renewable biomass verification 

tools become available. 

e. Approaches for Foreign Renewable 

Fuel 

EISA creates unique challenges 

related to the implementation and 

enforcement of the definition of 

renewable biomass for foreign-produced 

renewable fuel. In order to address these 

issues, we propose to require foreign 

producers of renewable fuel who export 

to the U.S. to meet the same compliance 

obligations as domestic renewable fuel 

producers. These obligations would 

include facility registration and 

submittal of independent engineering 

reviews (described in Section III.C 

below), and reporting, recordkeeping, 

and attest engagement requirements. 

They would also include the same 

obligations that domestic producers 

have for verifying that their feedstock 

meets the definition of renewable 

biomass as described above, such as 

certifying on each renewable fuel 

production report that their renewable 

fuel feedstock meets the definition of 

renewable biomass and working with 

their feedstock supplier(s) to ensure that 

they receive and maintain accurate and 

sufficient documentation in their 

records to support their claims. As 

under the RFS1 program for producers 

of cellulosic fuel, the foreign producer 

would be required to comply with 

additional requirements designed to 

ensure that enforcement of the 

regulations at the foreign production 

facility would not be compromised. For 

instance, foreign producers would be 

required to designate renewable fuel 

intended for export to the U.S. as such 

and segregate the volume until it 

reaches the U.S. and post a bond to 

ensure that penalties can be assessed in 

the event of a violation. Moreover, as a 

regulated party under the RFS2 

program, foreign producers would have 

to allow for potential visits by EPA 

enforcement personnel to review the 

completeness and accuracy of records 

and registration information. 

We propose that a foreign renewable 

fuel producer, like a domestic 

renewable fuel producer, could only 

produce and sell renewable fuel for 

export to the U.S. without RINs if he 

demonstrated that the land used to 

produce his feedstocks did not meet the 

definition of renewable biomass. This 

approach would ensure that foreign 

renewable fuel producers could not 

avoid the generation of RINs for fuel 

shipped to the U.S. simply by failing to 

make any demonstration regarding the 

land used to produce their feedstocks. 

Thus, foreign renewable fuel producers 

that export their product to the U.S. 

would be required to keep records of the 

type of land used to produce their 

feedstock regardless of whether RINs are 

generated or not. Section III.D.2.b 

outlines more specifically our proposed 

requirements for foreign renewable fuel 

producers. 

Importers will likely have less 

knowledge than a foreign renewable fuel 

producer would about the point of 

origin of their fuel’s feedstock and 

whether it meets the definition of 

renewable biomass. Therefore, we are 

proposing that in the event that a batch 

of foreign-produced renewable fuel does 

not have RINs accompanying it, an 

importer must obtain documentation 

from its producer that states whether or 

not the definition of renewable biomass 

was met by the fuel’s feedstock. With 

such documentation, the importer 

would be required to generate RINs (if 

the definition of renewable biomass is 

met) or would be prohibited from doing 

so (if the definition is not met) prior to 

introducing the fuel into commerce in 

the U.S. Without such documentation, 

the fuel would not be permitted for 

importation. Section III.D.2.c outlines 

our proposed requirements for 

importers more fully. 

We seek comment on whether and to 

what extent the approaches for ensuring 

compliance with the EISA’s land 

restrictions by foreign renewable fuel 

producers could or should differ from 

the proposed approach for domestic 

renewable fuel producers. In light of the 

challenges associated with enforcing the 

EISA’s land restrictions in foreign 

countries, we believe that it may be 

appropriate to require foreign renewable 

fuel producers to use an alternative 

method of demonstrating compliance 

with these requirements. We seek 

comment on whether foreign renewable 

producers exporting product to the U.S. 

should have to comply with any of the 

alternatives described for domestic 

renewable fuel producers under this 

section. For example, we seek comment 

on whether a foreign renewable fuel 

producer should have to demonstrate 

that it had a contract in place with its 

renewable feedstock producer that 

required designation and chain of 

custody and handling methods similar 

to one of the alternatives for domestic 

renewable fuel producers discussed 

above. We also seek comment on 

whether foreign renewable fuel 

producers that export product to the 

U.S. should have to provide EPA with 

the location of land from which they 

will or have acquired feedstocks, along 

with historical satellite or aerial imagery 

demonstrating that feedstocks from 

these lands meet the definition of 

renewable biomass. We seek comment 

on whether foreign renewable fuel 

producers should also be subject to the 

same quality assurance requirements 

relating to their feedstock sources as 

domestic renewable fuel producers, and 

whether they should have the same 

option to use an approved survey 

consortium in lieu of implementing 

their own individual quality assurance 

programs. 

We also seek comment on an 

alternative that would provide foreign 

renewable fuel producers an option of 

participating in RFS2 (in a manner 

consistent with our main proposal), or 

not participating at all. If they elected 

not to participate in RFS2, they could 

export renewable fuel to the United 

States without RINs, and without 

providing any documentation as to 

whether or not the fuel was made with 

renewable biomass. However, they 

would also have to meet requirements 

for segregating their fuel from renewable 

fuel for which RINs were generated, and 

the importer of their fuel would be 

required to track it to ensure that the 

fuel remains segregated in the U.S. and 

is not used by a domestic company for 

illegal RIN generation. This alternative 

would provide foreign renewable fuel 

producers an option not available to 

domestic renewable fuel producers, who 

in all cases would be required to 

document whether or not their 

feedstock met the definition of 

renewable biomass, and who would be 

required to generate RINs for their 

product if it was. As discussed in 

Section III.B.4.b.ii of this preamble, EPA 

believes that in order for obligated 

parties to meet the increasing annual 

volume requirements under RFS2, all 

qualifying renewable fuel will need to 

have RINs generated for it. Nonetheless, 

this alternative recognizes the potential 

difficulty of applying renewable 

biomass verification procedures in the 

international context, and provides an 

exemption process that EPA expects 

would only be used by relatively small 

producers for whom the burden of 

participating in the RFS2 program 

would outweigh the benefits, and whose 

total production volume would be 

negligible. 

C. Expanded Registration Process for 

Producers and Importers 

In order to implement and enforce the 

new restrictions on qualifying 

renewable fuel under RFS2, we are 

proposing that the registration process 

24942 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

for renewable fuel producers and 

importers be revised. Under the existing 

RFS1 program, all producers and 

importers of renewable fuel who 

produce or import more than 10,000 

gallons of fuel annually must register 

with EPA’s fuels program prior to 

generating RINs. Renewable fuel 

producer and importer registration 

under the existing RFS program consists 

of filling out two forms: 3520–20A 

(Fuels Programs Company/Entity 

Registration), which requires basic 

contact information for the company 

and basic business activity information 

(e.g., for an ethanol producer, they need 

to indicate that they are a RIN 

generator), and 3520–20B (Gasoline 

Programs Facility Registration) or 3520– 

20B1 (Diesel Programs Facility 

Registration), which requires basic 

contact information for each facility 

owned by the producer or importer. 

More detailed information on the 

renewable fuel production facility, such 

as production capacity and process, 

feedstocks, and products is not required 

for most producers or importers to 

generate RINs under RFS1 (producers of 

cellulosic biomass ethanol and wastederived ethanol are the exception to 

this). 

Due to the revised definitions of 

renewable fuel under EISA, as well as 

other changes, we believe it necessary to 

expand the registration process for 

renewable fuel producers and importers 

in order to implement the new program 

effectively. Specifically, generating and 

assigning a certain category of RIN to a 

volume of fuel is dependent on whether 

the feedstock used to produce the fuel 

meets the definition of renewable 

biomass, whether the lifecycle 

greenhouse gas emissions of the fuel 

meets a certain GHG reduction 

threshold and, in some cases, whether 

the renewable fuel production facility is 

considered to be grandfathered into the 

program. Unless we require producers, 

including foreign producers, and 

importers to provide us with 

information on their feedstocks, 

facilities, and products, we cannot 

adequately implement or enforce the 

program or have confidence that 

producers and importers are properly 

categorizing their fuel and generating 

RINs. In particular, our proposed 

approach for ensuring that the GHG 

emission reduction thresholds for each 

category of renewable fuel are met will 

require producers and importers to 

determine the proper category 

assignment for their fuel based on a 

combination of their feedstock, 

production processes, and products (see 

Section III.D.2 for the proposed list). 

Such information, therefore, is central to 

program implementation. Therefore, we 

are proposing new registration 

requirements for all domestic renewable 

fuel producers, importers, and foreign 

renewable fuel producers. We also plan 

on integrating registration procedures 

with the new EPA Moderated 

Transaction System, discussed in detail 

in Section IV.E of this preamble. We 

encourage those affected by the 

proposed registration requirements to 

review the document entitled ‘‘Proposed 

Information Collection Request (ICR) for 

the Renewable Fuels Standard (RFS2) 

Program—EPA ICR 2333.01,’’ and an 

Addendum to the proposed ICR, which 

have been placed in the public docket 

and to provide comments to us 

regarding the burdens associated with 

the proposed registration requirements. 

1. Domestic Renewable Fuel Producers 

The most significant proposed 

changes to the current registration 

system pertain to the information that a 

producer will need to provide EPA prior 

to generating RINs. As noted above, we 

are proposing that producers provide 

information about their products, 

feedstocks, and facilities in order to be 

registered for the RFS2 program. 

Information contained in a producer’s 

registration would be used to verify the 

validity of RINs generated and their 

proper categorization as either cellulosic 

biofuel, biomass-based diesel, advanced 

biofuel, or other renewable fuel. 

With respect to products, we are 

interested in the types of renewable fuel 

and co-products that a facility is capable 

of producing. With respect to 

feedstocks, we believe it is necessary to 

have on file a list of all the different 

feedstocks that a renewable fuel 

producer’s facility is capable of 

converting into renewable fuel. For 

example, if a renewable fuel producer 

produces fuel from both cellulosic 

material, such as corn stover, and noncellulosic material, such as corn starch, 

the producer may be eligible to generate 

RINs in two different categories 

(cellulosic biofuel and renewable fuel). 

This producer’s registration information 

would be required to list both of these 

feedstocks before we would allow two 

different categories of RINs to be 

generated. 

With respect to the producer’s 

facilities, we are proposing two types of 

information that would need to be 

reported to the Agency. First, we believe 

it is important to have information on 

file that describes each facility’s fuel 

production processes (e.g., wet mill, dry 

mill, thermochemical, etc.), and 

thermal/process energy source(s). 

Second, in order to determine what 

production volumes would be 

grandfathered and thus deemed to be in 

compliance with the 20% GHG 

threshold, we would require evidence 

and certification of the facility’s 

qualification under the definition of 

‘‘commence construction’’ as well as 

information necessary to establish it’s 

renewable fuel baseline volume per the 

proposal outlined in Section III.B.3 of 

this preamble. 

Under the existing RFS1 program, 

producers of cellulosic biomass and 

waste-derived ethanol are required to 

have an annual engineering review of 

their production records performed by 

an independent third party who is 

licensed Professional Engineer (P.E.) 

who works in the chemical engineering 

field. This independent third party need 

not be based in the United States, but 

must hold a P.E. Each review must be 

kept on file by both the producer and 

the engineer for five years. The 

independent third party must include 

documentation of its qualifications as 

part of the engineering review. Foreign 

producers of cellulosic biomass and 

waste-derived ethanol are also required 

to have an engineering review of their 

facilities, with a report submitted to 

EPA that describes in detail the physical 

plant and its operation. These 

requirements helps ensure that 

producers who claim to be producing 

such fuel, which earns 2.5 RINs per 

gallon rather than 1.0 RIN per gallon for 

corn-based ethanol under RFS1, are in 

fact doing so. 

We believe that the requirement for an 

on-site engineering review is an 

effective implementation tool and 

propose to adopt the requirement under 

RFS2, with the following changes. First, 

we propose expanding the applicability 

of the requirement to all renewable fuel 

producers due to the variability of 

production facilities, the increase in the 

number of categories of renewable fuels, 

and the importance of generating RINs 

in the correct category. Second, we 

propose that every renewable fuel 

producer must have the on-site 

engineering review of their facility 

performed in conjunction with his or 

her initial registration for the new RFS 

program in order to establish the proper 

basis for RIN generation, and every three 

years thereafter to verify that the fuel 

pathways established in their initial 

registration are still applicable. These 

requirements would apply unless the 

renewable fuel producer updates its 

facility registration information to 

qualify for a new RIN category (i.e., D 

code), in which case the review would 

need to be performed within 60 days of 

the registration update. Finally, we 

propose that producers be required to 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24943 

submit a copy of their independent 

engineering review to EPA rather than 

simply maintaining it in their records. 

We believe that this extra step is 

necessary for verification and 

enforcement purposes. 

In addition to the new registration 

requirements for all renewable fuel 

producers who produce greater than 

10,000 gallons of product each year, we 

seek comment on whether to require 

renewable fuel producers and importers 

in the U.S. who produce or import less 

than 10,000 gallons per year to register 

basic information about their company 

and facility (or facilities) with EPA, 

similar to information currently 

required of renewable fuel producers 

under RFS1. This information would 

complement information submitted to 

EPA under the Fuels and Fuel Additives 

Registration System (FFARS) program to 

help ensure that EPA has a complete 

record of renewable fuel production and 

importation in the U.S. 

2. Foreign Renewable Fuel Producers 

Under the current RFS program, 

foreign renewable fuel producers of 

cellulosic biomass ethanol and wastederived ethanol may apply to EPA to 

generate RINs for their own fuel. This 

allows a foreign producer of this 

renewable fuel to obtain the same 

benefits of higher credit value as 

domestic producers of this category of 

renewable fuel. Under the RFS1 

regulations, the foreign fuel producer 

must meet a variety of requirements 

established to make the program 

effective and enforceable with respect to 

a foreign producer. These requirements 

mirror a number of similar fuel 

provisions that apply to foreign refiners 

in other fuels programs. For RFS2, we 

propose that foreign producers of 

renewable fuel must meet the same 

requirements as domestic producers, 

including registering information about 

their feedstocks, facilities, and products, 

as well as submitting an on-site 

independent engineering review of their 

facilities at the time of registration for 

the program and every three years 

thereafter. These requirements would 

apply to all foreign renewable fuel 

producers who export their products to 

the U.S., whether or not they qualify to 

generate RINs for their fuel. They would 

also be subject to the variety of 

enforcement related provisions that 

apply under RFS1 to foreign producers 

of cellulosic biomass or waste derived 

ethanol. 

As discussed in Section III.C.1, the 

existing RFS1 program requires that the 

independent engineering review be 

conducted by an independent third 

party who is a licensed P.E. who works 

in the chemical engineering field. This 

P.E. need not be based in the United 

States. The independent third party 

must include documentation of its 

qualifications as part of the engineering 

review. 

Since implementation of RFS1 we 

have received questions about engineers 

who are licensed by other countries that 

may have equivalent licensing 

requirements to those associated with 

the P.E. designation in the United 

States. The existing RFS1 program does 

not permit independent third party 

review by a party who is not a licensed 

P.E. We invite comment on whether or 

not we should permit independent third 

parties who are based in—and licensed 

by—foreign countries and who work in 

the chemical engineering field to 

demonstrate the foreign equivalency of 

a P.E. license. 

We also seek comment on requiring 

foreign renewable fuel producers to 

provide EPA with the location of land 

from which they will acquire 

feedstocks, along with historical 

satellite or aerial imagery demonstrating 

that the lands from which they acquire 

feedstock are eligible under the 

definition of renewable biomass (see 

Section III.B.4 for a full discussion of 

our proposed and alternative 

approaches for foreign renewable fuel 

producers to verify their feedstocks 

meet the definition of ‘‘renewable 

biomass’’). 

3. Renewable Fuel Importers 

A renewable fuel importer is required 

under RFS1 to register basic information 

about their company with EPA prior to 

generating RINs. Under the proposed 

new RFS2 program, we are proposing 

that only in limited cases can importers 

generate RINs for imported fuel that 

they receive without RINs. In any case, 

whether they receive fuel with or 

without RINs, an importer must rely on 

his supplier, a foreign renewable fuel 

producer, to provide documentation to 

support any claims for their decision to 

generate or not to generate RINs. An 

importer may have an agreement with a 

foreign renewable fuel producer for the 

importer to generate RINs if the foreign 

producer has not done so already. 

However, the foreign renewable fuel 

producer must be registered with EPA 

as noted above. Section III.D.2.c 

describes our proposed RIN generating 

restrictions and requirements for 

importers under RFS2. 

4. Process and Timing 

We intend to make forms for 

expanded registration for renewable fuel 

producers and importers available 

electronically, with paper registration 

only in exceptional cases. We propose 

that registration forms will have to be 

submitted by January 1, 2010 (the 

proposed effective date of the final RFS2 

regulations), or 60 days prior to a 

producer producing or importer 

importing any renewable fuel, 

whichever dates comes later. If a 

producer changes to a feedstock that is 

not listed in his registration information 

on file with EPA but the feedstock will 

not incur a change of RIN category for 

the fuel (i.e., a change in the appropriate 

D code), then we propose that the 

producer must update his registration 

information within seven (7) days of the 

change. However, if a producer’s 

feedstock, facility (including industrial 

processes or thermal energy source), or 

products undergo changes that would 

qualify his renewable fuel for a new RIN 

category (and thus a new D code), then 

we propose that such an update would 

need to be submitted at least 60 days 

prior to the change, followed by 

submittal of a complete on-site 

independent engineering review of the 

producer’s facility also within 60 days 

of the change. 

D. Generation of RINs 

Under RFS2, each RIN would 

continue to be generated by the 

producer or importer of the renewable 

fuel, as in the RFS1 program. In order 

to determine the number of RINs that 

must be generated and assigned to a 

batch of renewable fuel, the actual 

volume of the batch of renewable fuel 

must be multiplied by the appropriate 

Equivalence Value. The producer or 

importer must also determine the 

appropriate D code to assign to the RIN 

to identify which of the four standards 

the RIN can be used to meet. This 

section describes these two aspects of 

the generation of RINs. We propose that 

other aspects of the generation of RINs, 

such as the definition of a batch and 

temperature standardization, as well as 

the assignment of RINs to batches, 

should remain unchanged from the 

RFS1 requirements. 

1. Equivalence Values 

For RFS1, we interpreted CAA section 

211(o) as allowing us to develop 

Equivalence Values representing the 

number of gallons that can be claimed 

for compliance purposes for every 

physical gallon of renewable fuel. We 

described how the use of Equivalence 

Values adjusted for renewable content 

and based on energy content in 

comparison to the energy content of 

ethanol was consistent with 

Congressional intent to treat different 

renewable fuels differently in different 

circumstances, and to provide 

24944 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

incentives for use of renewable fuels in 

certain circumstances, as evidenced by 

the specific circumstances addressed by 

Congress. This included the direction 

that EPA establish ‘‘appropriate’’ credit 

values in certain circumstances, as well 

as provisions in the statute providing for 

different credit values to be assigned to 

the same volume of different types of 

renewable fuels (e.g., cellulosic and 

waste-derived fuels). We also noted that 

the use of Equivalence Values based on 

energy content was an appropriate 

measure of the extent to which a 

renewable fuel would replace or reduce 

the quantity of petroleum or other fossil 

fuel present in a fuel mixture. The result 

was an Equivalence Value for ethanol of 

1.0, for butanol of 1.3, for biodiesel 

(mono alkyl ester) of 1.5, and for nonester renewable diesel of 1.7. EPA stated 

that these provisions indicated that 

Congress did not intend to limit the RFS 

program solely to a straight volume 

measurement of gallons. EPA also noted 

that the use of Equivalence Values 

would not interfere with meeting the 

overall volume goals specified by 

Congress, given the various provisions 

that make achievement of the specified 

volumes imprecise. See 72 FR 23918– 

23920, and 71 FR 55570–55571. 

EISA has not changed certain of the 

statutory provisions we looked to for 

support under RFS1 in establishing 

Equivalence Values based on relative 

volumetric energy content in 

comparison to ethanol. For instance, 

CAA 211(o) continues to give EPA the 

authority to determine an ‘‘appropriate’’ 

credit for biodiesel, and also directs 

EPA to determine the ‘‘appropriate’’ 

amount of credit for renewable fuel use 

in excess of the required volumes. 

However, EISA made a number of 

other changes to CAA section 211(o) 

that impact our consideration of 

Equivalence Values in the context of the 

RFS2 program. For instance, EISA 

eliminated the 2.5-to-1 credit for 

cellulosic biomass ethanol and wastederived ethanol and replaced this 

provision with large mandated volumes 

of cellulosic biofuel and advanced 

biofuels. Under the RFS1 program, an 

Equivalence Value of 2.5 applies to 

these types of ethanol through the end 

of 2012. Under the new RFS2 program, 

these types of ethanol would have an 

Equivalence Value of 1.0, consistent 

with all other forms of ethanol. 

EISA also expanded the program to 

include four separate categories of 

renewable fuel (cellulosic biofuel, 

biomass-based diesel, advanced biofuel, 

and total renewable fuel) and included 

GHG thresholds in the definitions of 

each category. Each of these categories 

of renewable fuel has its own volume 

requirement, and thus there will exist a 

guaranteed market for each. As a result 

there may no longer be a need for 

additional incentives for certain fuels in 

the form of Equivalence Values greater 

than 1.0. In addition, the use of an 

energy-based approach to Equivalence 

Values raises some questions, discussed 

below, concerning the impact of such 

Equivalence Values on the biomassbased diesel volume requirement and in 

the initial years on the advanced biofuel 

volume requirement. Overall EPA 

believes that the statute continues to be 

ambiguous on this issue, and we are 

therefore co-proposing and seeking 

comment on two options for 

Equivalence Values: 

1. Equivalence Values would be based 

on the energy content and renewable 

content of each renewable fuel in 

comparison to denatured ethanol, 

consistent with the approach under 

RFS1. 

2. All liquid renewable fuels would be 

counted strictly on the basis of their 

measured volumes, and the Equivalence 

Values for all renewable fuels would be 

1.0 (essentially, Equivalence Values 

would no longer apply). 

While these two different approaches 

to volume would have an impact on the 

market values of renewable fuels with 

different energy contents as explained 

more fully below, the overall impact on 

the program would likely be small since 

we are projecting that the overwhelming 

majority of renewable fuels will be 

ethanol (see further discussion in 

Section V.A.2). 

Under either option, non-liquid 

renewable fuels such as biogas and 

renewable electricity would continue to 

be valued based on the energy contained 

in one gallon of denatured ethanol. In 

the RFS1 final rulemaking, we specified 

that 77,550 Btu of biogas be counted as 

the equivalent of 1 gallon of renewable 

fuel with an assigned Equivalence Value 

of 1.0. We propose to maintain this 

approach to non-liquid renewable fuels 

under the RFS2 program under either 

approach to Equivalence Values, but 

with a small modification to make the 

ethanol energy content more accurate. 

The energy content of denatured ethanol 

was specified as 77,550 Btu/gal under 

RFS1, but a more accurate value would 

be 77,930 Btu/gal. Thus we propose to 

use 77,930 Btu to convert biogas and 

renewable electricity into volumes of 

renewable fuel under RFS2. 

Under the second option in which all 

liquid renewable fuels would be 

counted strictly on the basis of their 

measured volumes, we would need to 

determine how to treat the small 

amount of denaturant in ethanol and the 

nonrenewable portion of biodiesel. 

Under RFS1, Equivalence Values were 

determined from a formula that 

included measures of both volumetric 

energy content and renewable content. 

The renewable content was intended to 

take into account the portion, if any, of 

a renewable fuel that originated from a 

fossil fuel feedstock. EISA eliminated 

the statutory language on which the 

inclusion of renewable content was 

based, and instead restricts renewable 

fuels that are valid under the RFS2 

program to those produced from 

renewable biomass. In the case of fuels 

produced from both renewable and 

nonrenewable feedstocks, we have 

interpreted this to mean only that 

portion of the volume attributable to the 

renewable feedstocks (see further 

discussion in Section III.D.4 below). 

However, we do not believe that this 

approach is appropriate for the 

denaturant in ethanol and the small 

amount of non-renewable methanol 

used in the production of biodiesel, 

since Congress clearly intended that 

ethanol and biodiesel be included as a 

renewable fuel, and they are only used 

as a fuel under these circumstances. We 

therefore propose to treat the denaturant 

in ethanol and the nonrenewable 

portion of biodiesel as de minimus and 

thus count them as part of the 

renewable fuel volume under an 

approach to Equivalence Values in 

which all liquid renewable fuels would 

be counted strictly on the basis of their 

measured volumes. As a result, under 

this co-proposed approach we are 

proposing that the full formula used to 

calculate Equivalence Values under 

RFS1 be eliminated from the regulations 

and that the Equivalence Value for all 

renewable fuels be specified as 1.0. 

Nevertheless, we seek comment on this 

approach. 

Although there are several reasons for 

a straight volume approach as discussed 

above, there are also several reasons to 

maintain the ethanol-equivalent energy 

content approach to Equivalence Values 

of RFS1. For instance, in our 

discussions with stakeholders, some 

have argued that the existence of four 

standards is not a sufficient reason to 

eliminate the use of energy-based 

Equivalence Values for RFS2. The four 

categories are defined in such a way that 

a variety of different types of renewable 

fuel could qualify for each category, 

such that no single specific type of 

renewable fuel will have a guaranteed 

market. For example, the cellulosic 

biofuel requirement could be met with 

both cellulosic ethanol or cellulosic 

diesel. As a result, the existence of four 

standards under RFS2 may not obviate 

the value of standardizing for energy 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24945 

24Another example would be a fermentation 

process in which one ton of cellulose could be used 

to produce either 70 gallons of ethanol or 55 gallons 

of butanol. 

25The proposed regulations and the ensuing 

discussion in Sections III and IV of this proposal 

reflect straight volume approach, however, the 

impacts analysis of the program are calculated 

using volumes based on ethanol-equivalent energy 

content. Were we to maintain the energy content 

approach to Equivalence Values, then we believe 

the biomass-based diesel standard should be treated 

in effect as a biodiesel volume, reflecting the nature 

of this standard, while the other three standards 

would be treated as ethanol-equivalent volumes. In 

order to effectuate this, we are considering two 

approaches. Under either approach all RINs would 

be generated based on ethanol-equivalent volume, 

including biomass-based diesel RINs. Under one 

approach, we would propose that the biomassbased diesel standard also be expressed as an 

ethanol-equivalent volume (e.g., 1.5 billion ethanolequivalent gallons in 2012). Another approach 

would be to have the standard expressed as a 

volume of biomass-based diesel, and to require the 

biomass-based diesel RINs be adjusted back to a 

volume basis, with this adjustment just for purposes 

of the biomass-based diesel standard but not for 

purposes of the other fuels mandates. Either 

approach would have the same result. 

content, which provides a level playing 

field under RFS1 for various types of 

renewable fuels based on energy 

content. 

More importantly, they argue that a 

straight volume approach would be 

likely to create a disincentive for the 

development of new renewable fuels 

that have a higher energy content than 

ethanol in the same way as the current 

ethanol tax credit structure. For a given 

mass of feedstock, the volume of 

renewable fuel that can be produced is 

roughly inversely proportional to its 

energy content. For instance, one ton of 

biomass could be gasified and converted 

to syngas, which could then be 

catalytically reformed into either 90 

gallons of ethanol (and other alcohols) 

or 50 gallons of diesel fuel (and 

naphtha).24 If RINs were assigned on a 

straight volume basis, the producer 

could maximize the number of RINs he 

is able to generate and sell by producing 

ethanol instead of diesel. Thus, even if 

the market would otherwise lean 

towards demanding greater volumes of 

diesel, the greater RIN value for 

producing ethanol may favor its 

production instead. However, if the 

energy-based Equivalence Values were 

maintained, the producer could assign 

1.7 RINs to each gallon of diesel made 

from biomass in comparison to 1.0 RIN 

to each gallon of ethanol from biomass, 

and the total number of RINs generated 

would be essentially the same for the 

diesel as it would be for the ethanol. 

The use of energy-based Equivalence 

Values could thus provide a level 

playing field in terms of the RFS 

program’s incentives to produce 

different types of renewable fuel from 

the available feedstocks. The market 

would then be free to choose the most 

appropriate renewable fuels without any 

bias imposed by the RFS regulations, 

and the costs imposed on different types 

of renewable fuel through the 

assignment of RINs would be more 

evenly aligned with the ability of those 

fuels to power vehicles and engines, and 

displace fossil fuel-based gasoline or 

diesel. 

Moreover, the technologies for 

producing more energy-dense fuels such 

as cellulosic diesel are still in the early 

stages of development and may benefit 

from not having to overcome the 

disincentive in the form of the same 

Equivalence Value based on straight 

volume. Given the projected tightness in 

the distillate market and relative excess 

supply in the gasoline market in the 

coming years, allowing the market to 

choose freely may be important to 

overall fuel supply. In the extreme, the 

cellulosic biofuel standard could then 

be met by roughly 10 billion gallons of 

a cellulosic diesel fuel instead of the 16 

billion gallons of cellulosic ethanol 

assumed for the impacts analysis of this 

proposal. The same amount of 

petroleum energy would be displaced, 

but by different physical volumes. 

As discussed above, there are no 

provisions in EISA that explicitly 

instruct the Agency to change from the 

approach to Equivalence Values 

adopted in RFS1. However, there is a 

question of how to address the biomassbased diesel requirement under such an 

approach. In that context, it does appear 

that Congress intended the required 

volumes of biomass-based diesel to be 

treated as diesel volumes rather than 

ethanol-equivalent volumes. Therefore 

EPA proposes that, for the biomassbased diesel volume mandate under an 

ethanol-equivalent energy content 

approach to Equivalence Values, the 

compliance calculations would be 

structured such that this requirement is 

treated in effect as a straight volumebased requirement.25

In addition, it is also clear that 

Congress established the advanced 

biofuel standard in EISA to begin to take 

affect in 2009. However, if we maintain 

the ethanol-equivalent energy content 

approach for RFS2, and biodiesel 

continues to have an Equivalence Value 

of 1.5, then from 2009–2012 the 

combination of the biomass-based diesel 

standard and the cellulosic biofuel 

standard will meet or exceed the 

advanced biofuel standard. Unless we 

were to waive a portion of either the 

biomass-based diesel standard or the 

cellulosic biofuel standard, the 

advanced biofuel standard would not 

have an independent effect until 2013. 

While EPA recognizes this, EPA 

believes that the long term benefits of an 

energy based Equivalence Value may be 

significantly greater than any temporary 

diminishment in the real world impact 

of the advanced biofuel mandate. 

In recognition of the competing 

perspectives, we request comment on 

both co-proposed approaches to the 

Equivalence Values: (1) Retaining the 

energy-based approach of the RFS1 

program, and (2) a straight volume 

approach measured in liquid gallons of 

renewable fuel. 

2. Fuel Pathways and Assignment of D 

Codes 

As described in Section III.A, we 

propose that RINs under RFS2 would 

continue to have the same number of 

digits and code definitions as under 

RFS1. The one change would be that, 

while the D code would continue to 

identify the standard to which the RIN 

could be applied, it would be modified 

to have four values corresponding to the 

four different renewable fuel categories 

defined in EISA. These four D code 

values and the corresponding categories 

are shown in Table III.A–1. 

In order to generate RINs for 

renewable fuel that meets the various 

eligibility requirements (see Section 

III.B), a producer or importer must know 

which D code to assign to those RINs. 

We propose that a producer or importer 

would determine the appropriate D code 

using a lookup table in the regulations. 

The lookup table would list various 

combinations of fuel type, production 

process, and feedstock, and the 

producer or importer would choose the 

appropriate combination representing 

the fuel he is producing and for which 

he is generating RINs. Parties generating 

RINs would be required to use the D 

code specified in the lookup table and 

would not be permitted to use a D code 

representing a broader renewable fuel 

category. For example, a party whose 

fuel qualified as biomass-based diesel 

could not choose to categorize that fuel 

as advanced biofuel or general 

renewable fuel. 

This section describes our proposed 

approach to the assignment of D codes 

to RINs for domestic producers, foreign 

producers, and importers of renewable 

fuel. Subsequent sections address the 

generation of RINs in special 

circumstances, such as when a 

production facility has multiple 

applicable combinations of feedstock, 

fuel type, and production process 

within a calendar year, production 

facilities that co-process renewable 

biomass and fossil fuels, and production 

24946 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

facilities for which the lookup table 

does not provide an applicable D code. 

a. Domestic Producers 

For domestic producers, the lookup 

table would identify individual fuel 

‘‘pathways’’ comprised of unique 

combinations of the type of renewable 

fuel being produced, the feedstock used 

to produce the renewable fuel, and a 

description of the production process. 

Each pathway would be assigned to one 

of the four specific D codes on the basis 

of the revised renewable fuel definitions 

provided in EISA and our assessment of 

the GHG lifecycle performance for that 

pathway. A description of the lifecycle 

assessment of each fuel pathway and the 

process we used for determining the 

associated D code can be found in 

Section VI. Note that the subsequent 

generation of RINs would also require as 

a prerequisite that the feedstocks used 

to make the renewable fuel meet the 

definition of ‘‘renewable biomass’’ as 

described in Section III.B.4, including 

applicable land use restrictions. 

Moreover, a domestic producer could 

not introduce renewable fuel into 

commerce without generating RINs 

unless he had records demonstrating 

that the feedstocks used to produce the 

fuel did not meet the definition of 

renewable biomass. See Section 

III.B.4.b.ii for further discussion of this 

issue. 

Through our assessment of the 

lifecycle GHG impacts of different 

pathways and the application of the 

EISA definitions for each of the four 

categories of renewable fuel, including 

the GHG thresholds, we have 

determined that all four categories 

would have pathways that could be 

used to meet the Act’s volume 

requirements. For example, ethanol 

made from corn stover or switchgrass in 

an enzymatic hydrolysis process would 

count as cellulosic biofuel. Biodiesel 

made from waste grease could count as 

biomass-based diesel. Ethanol made 

from sugarcane sugar may count as 

advanced biofuel depending on the 

results of the lifecycle assessment 

conducted for the final rule and a 

determination about whether the GHG 

threshold for advanced biofuel should 

be adjusted downward. Finally, under 

an assumed 100-year timeframe and 2% 

discount rate for GHG emissions 

impacts, a variety of pathways would 

count as generic renewable fuel under 

the RFS2 program, including ethanol 

made from corn starch in a facility 

powered by biomass combustion and 

biodiesel made from soybean oil. The 

complete list of pathways that would be 

valid under our proposed RFS program 

is provided in the regulations at 

§ 80.1426(d), based upon an assumed 

100-year timeframe and 2% discount 

rate for GHG emission impacts. 

Domestic producers would choose the 

appropriate D code from the lookup 

table in the regulations based on the fuel 

pathway that describes their facility. 

The fuel pathway must be specified by 

the producer in the registration process 

as described in Section III.C. If there 

were changes to a domestic producer’s 

facility or feedstock such that their fuel 

would require a D code that was 

different from any D code(s) which their 

existing registration information already 

allowed, the producer would be 

required to revise its registration 

information with EPA 30 days prior to 

changing the applicable D code it uses 

to generate RINs. Situations in which 

multiple fuel pathways could apply to 

a single facility are addressed in Section 

III.D.3 below. 

For producers for whom none of the 

defined fuel pathways in the lookup 

table would apply, we propose two 

possible treatments. First, such 

producers may be able to generate RINs 

through our proposed system of default 

D codes as described in Section III.D.5 

below. Second, if a producer meets the 

criteria for grandfathered status as 

described in Section III.B.3 and his fuel 

meets the definition of renewable fuel as 

described in Section III.B.1, he could 

continue to generate RINs for his fuel 

but would use a D code of 4 for those 

RINs generated under the grandfathering 

provisions. If a producer was not 

covered by either of these two 

treatments, we propose that he would 

not be permitted to generate RINs for his 

product until the lookup table in the 

regulations was modified to include a 

pathway applicable to his operations. 

A diesel fuel product produced from 

cellulosic feedstocks that meets the 60% 

GHG threshold could qualify as either 

cellulosic biofuel or biomass-based 

diesel. As a result, we are proposing that 

the producer of such ‘‘cellulosic diesel’’ 

be given the choice of whether to 

categorize his product as either 

cellulosic biofuel or biomass-based 

diesel. This would allow the producer 

to market his product and the associated 

RINs on the basis of market demand. 

However, we request comment on an 

alternative approach as shown in Table 

III.D.2.a–1 in which an additional D 

code would be defined to represent 

cellulosic diesel and an obligated party 

would be given the choice of using 

cellulosic diesel RINs either to meet his 

or her RVO for cellulosic biofuel or for 

biomass-based diesel. 

TABLE III.D.2.a–1—ALTERNATIVE D CODE DEFINITIONS TO ACCOMMODATE CELLULOSIC DIESEL

D value Meaning under RFS1 Meaning under RFS2 

1 ...................................................... Cellulosic biomass ethanol ........................................ Cellulosic biofuel. 

2 ...................................................... Any renewable fuel that is not cellulosic biomass 

ethanol.

Biomass-based diesel. 

3 ...................................................... Not applicable ............................................................ Cellulosic biofuel or biomass-based diesel. 

4 ...................................................... Not applicable ............................................................ Advanced biofuel. 

5 ...................................................... Not applicable ............................................................ Renewable fuel. 

Under this alternative, producers of 

cellulosic diesel would assign a D code 

of 3 to their product rather than being 

given a choice of whether to assign a D 

code of 1 or 2. Any obligated party that 

acquired a RIN with a D code of 3 could 

apply that RIN to either its cellulosic 

biofuel or biomass-based diesel 

obligation, but not both. The advantage 

of this alternative approach is that it 

reflects the full compliance value for the 

product, and hence its potential value to 

an obligated party. The obligated party 

is then given the ability to make a 

choice about how to treat cellulosic 

diesel based on the market price and 

availability of RINs with D codes of 1 

and 2. We request comment on this 

alternative approach to the designation 

of D codes for cellulosic diesel. 

b. Foreign Producers 

Under RFS1, foreign producers have 

the option of generating RINs for the 

renewable fuel that they export to the 

U.S. if they want to designate their fuel 

as cellulosic biomass ethanol or wastederived ethanol, and thereby take 

advantage of the additional 1.5 credit 

value afforded by the 2.5 Equivalence 

Value for such products. In order to 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24947 

ensure that EPA has the ability to 

enforce the regulations relating to the 

generation of RINs from such foreign 

ethanol producers, the RFS1 regulations 

require them to post a bond and submit 

to third-party engineering reviews of 

their production process. If a foreign 

producer does not generate RINs for the 

renewable fuel that it exports to the 

U.S., the U.S. importer is responsible for 

generating the RINs associated with the 

imported renewable fuel. 

EISA creates unique challenges in the 

implementation and enforcement of the 

renewable fuel standards for imported 

renewable fuel. Unlike our other fuels 

programs, EPA cannot determine 

whether a particular shipment of 

renewable fuel is eligible to generate 

RINs under the new program by testing 

the fuel itself. Instead, information 

regarding the feedstock that was used to 

produce renewable fuel and the process 

by which it was produced is vital to 

determining the proper renewable fuel 

category and RIN type for the imported 

fuel. It is for these reasons that we 

required foreign producers of cellulosic 

biomass ethanol or waste-derived 

ethanol under RFS1 to take additional 

steps to ensure the validity of the RINs 

they generate. 

For RFS2 we are proposing a similar 

approach to that taken under RFS1, but 

with a number of modifications to 

account for the changes that EISA makes 

to the definition of renewable fuel. 

Thus, we propose that foreign producers 

would have the option of generating 

RINs for any renewable fuel (not just the 

cellulosic biofuel category) that they 

export to the U.S. If the foreign producer 

did not generate RINs, the importer 

would be required to generate RINs for 

the imported renewable fuel. Our 

proposed importer provisions are 

covered in more detail in Section 

III.D.2.c below. 

In general, we propose that foreign 

producers of renewable fuel who intend 

to export their fuel to the U.S. would 

use the same process as domestic 

producers to generate RINs, namely the 

lookup table to identify the appropriate 

D code as a function of fuel type, 

production process, and feedstock. They 

would be required to be registered with 

the EPA as a producer under the RFS2 

program and would be subject to the 

same recordkeeping, reporting, and 

attest engagement requirements as 

domestic producers, including those 

provisions associated with ensuring that 

the feedstocks they use meet the 

definition of renewable biomass. They 

would also be required to submit to 

third-party engineering reviews of their 

production process and use of 

feedstocks, just as domestic producers 

are. As under the RFS1 program, the 

foreign producer would also be required 

to comply with additional requirements 

designed to ensure that enforcement of 

the regulations at the foreign production 

facility would not be compromised. For 

instance, foreign producers would be 

required to designate renewable fuel 

intended for export to the U.S. as such 

and segregate the volume until it 

reaches the U.S. in order to ensure that 

RINs are only generated for volumes 

imported into the U.S. Foreign 

producers would also be required to 

post a bond to ensure that penalties can 

be assessed in the event of a violation. 

Moreover, as a regulated party under the 

RFS2 program, foreign producers must 

allow for potential visits by EPA 

enforcement personnel to review the 

completeness and accuracy of records 

and registration information. Noncompliance with any of these 

requirements could be grounds for 

refusing to allow renewable fuel from 

such a foreign producer to be imported 

into the U.S. 

For RFS2, we are proposing a number 

of additional provisions to address 

foreign companies that produce 

renewable fuel for export to the United 

States, but that do not generate their 

own RINs for that renewable fuel. These 

provisions are intended to account for 

the greater difficulties in verifying the 

validity of RINs for imported renewable 

fuel when the importer is generating the 

RINs, given that the importer would 

generally not have direct knowledge of 

the feedstocks used to produce the 

renewable fuel, the land used to grow 

those feedstocks, or the fuel production 

process. We believe that these 

additional provisions would be 

necessary to ensure that RINs 

representing imported renewable fuel 

and used by obligated parties have been 

generated appropriately. 

As described more fully in Section 

III.D.2.c below, importers would only be 

allowed to import renewable fuel from 

registered foreign producers and would 

be required to generate RINs for all 

imported renewable fuel that has not 

been assigned RINs by the foreign 

producer. Like domestic and foreign 

producers who generate RINs, the 

importer must be able to determine if 

the renewable biomass definition has 

been met before generating RINs. The 

importer must also have enough 

information about the production 

process and feedstock to be able to use 

the lookup table to identify the 

appropriate D code to include in the 

RINs he generates. Since the foreign 

producer is the only party who can 

provide this information, we believe 

that it would be appropriate to require 

the foreign producer of any renewable 

fuel exported to the U.S. to provide this 

information to the U.S. importer before 

the renewable fuel enters U.S. 

commerce even if the foreign producer 

is not generating RINs himself. 

Moreover, the foreign producer should 

be liable for the accuracy of this 

information just as if he were the party 

generating RINs. Therefore, in order to 

ensure that RINs are valid regardless of 

who generates them, we propose that all 

the provisions described above that 

would be applicable to a foreign 

producer who generates RINs would 

also apply to a foreign producer who 

does not generate RINs but still exports 

renewable fuel to the U.S. This would 

include registration with the EPA under 

the RFS2 program, being subject to all 

the recordkeeping, reporting, and attest 

engagement requirements, and posting a 

bond. The only exception would be that 

the foreign producer would not be 

required to segregate a specific volume 

between the foreign producer’s facility 

and the import facility if the foreign 

producer is not generating RINs, since 

the importer would be the primary party 

responsible for measuring the volume 

before generating RINs. 

Although we are proposing that RINs 

for imported renewable fuel could be 

generated by either the importer or the 

foreign producer, it is possible that this 

could result in difficulty in verifying 

that only one set of RINs has been 

generated for a given volume of 

renewable fuel. One possible solution 

would be to require a foreign producer 

to make a decision regarding RIN 

generation that would apply for an 

entire calendar year. Under this 

approach, a foreign producer would be 

required to either generate RINs for all 

the renewable fuel that he exports to the 

U.S within a calendar year, or to 

generate no RINs for the renewable fuel 

that he exports to the U.S within a 

calendar year. While we are not 

proposing this approach it today’s 

action, we request comment on it. 

As described in Section III.B.4.b.ii, we 

are proposing that domestic producers 

could only introduce renewable fuel 

into commerce without generating RINs 

if they demonstrate that feedstocks used 

to produce the fuel did not meet the 

definition of renewable biomass. Thus it 

would not be sufficient for a domestic 

producer to simply fail to make a 

demonstration that the renewable 

biomass definition had been met, and 

thereby avoid generation of RINs. We 

propose that a similar approach would 

be applied to imported renewable fuel. 

As a result, all renewable fuel that 

would be imported into the U.S. would 

be required to come with 

24948 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

documentation regarding the status of 

the feedstock’s compliance with the 

renewable biomass definition. In the 

case of documentation indicating that 

the renewable biomass definition had 

been met, the importer would be 

required to generate RINs. In the case of 

documentation indicating that the 

renewable biomass definition had not 

been met, the importer would be 

prohibited from generating RINs but 

could still import the renewable fuel 

into the U.S. Renewable fuel that was 

not accompanied by any documentation 

regarding the status of the feedstock’s 

compliance with the renewable biomass 

definition could not be imported into 

the U.S. 

Our proposed approach to foreign 

producers is consistent with the 

approach we propose taking for 

domestic producers, in that the 

producer is responsible for ensuring that 

RINs generated for renewable fuel used 

in the U.S. are valid and categorized 

appropriately. While our proposed 

approach to foreign producers of 

renewable fuel under RFS2 would 

require additional actions in 

comparison to their general 

requirements under RFS1, we believe 

these provisions would be necessary to 

ensure that the volume mandates shown 

in Table II.A.1–1 are met, given the new 

definitions for renewable fuel and 

renewable biomass in EISA. We request 

comment on our proposed approach to 

foreign producers. 

c. Importers 

Under RFS1, importers who import 

more than 10,000 gallons in a calendar 

year must generate RINs for all imported 

renewable fuel based on its type, except 

for cases in which the foreign producer 

generated RINs for cellulosic biomass 

ethanol or waste-derived ethanol. Due to 

the new definitions of renewable fuel 

and renewable biomass in EISA, 

importers could no longer generate RINs 

under RFS2 on the basis of fuel type 

alone. Instead, they must be able to 

determine whether or not the renewable 

biomass definition has been met for the 

renewable fuel they intend to import, 

and they must also have sufficient 

information about the feedstock and 

process used to make the renewable fuel 

to allow them to identify the 

appropriate D code from the lookup 

table for use in the RINs they generate. 

As described in Section III.D.2.b above, 

we are proposing that in order for an 

importer to import renewable fuel into 

the U.S., the foreign producer would 

have to provide this information to the 

importer. 

Under today’s proposal, importers 

would be able to import renewable fuels 

only under one of the following 

scenarios: 

1. The importer receives RINs 

generated by the registered foreign 

producer when he imports a volume of 

renewable fuel. 

2. The imported renewable fuel is not 

accompanied by RINs generated by the 

registered foreign producer, and the 

foreign producer provides the importer 

with: 

—A demonstration that the renewable 

biomass definition has been met for 

the volume of renewable fuel being 

imported. 

—Information about the feedstock and 

production process used to produce 

the renewable fuel. 

In this case, the importer would be 

required to generate RINs for the 

imported renewable fuel before 

introducing it into commerce in the 

contiguous 48 states or Hawaii. 

3. The imported renewable fuel is not 

accompanied by RINs generated by the 

registered foreign producer, and the 

foreign producer provides the importer 

with a demonstration that the renewable 

biomass definition has not been met for 

the volume of renewable fuel being 

imported. See further discussion of this 

issue in Section III.B.4.b.ii. The 

importer would be prohibited from 

generating RINs for the imported 

volume, but could still introduce the 

renewable fuel into commerce. 

If none of these scenarios applied, the 

importer would be prohibited from 

importing renewable fuel. Our proposed 

approach to imported fuels would apply 

to both neat renewable fuel and 

renewable fuels blended into gasoline or 

diesel. 

As described in Section III.B.4.e, we 

also seek comment on an alternative 

approach to imported renewable fuel in 

which foreign renewable fuel producers 

would have the option of not 

participating in RFS2 but still export 

renewable fuel to the U.S. Under this 

alternative approach, foreign producers 

would have to meet requirements for 

segregating their fuel from renewable 

fuel for which RINs were generated, and 

the importer of their fuel would be 

required to track it to ensure that the 

fuel remains segregated in the U.S. and 

is not used by a domestic company for 

illegal RIN generation. 

While it is important that all RINs be 

based on accurate information about the 

feedstocks and production process used 

to produce the renewable fuel, it may 

not be necessary to place the burden 

upon importers for acquiring this 

information before they generate RINs. 

Instead, an alternative approach would 

prohibit importers from generating any 

RINs, and instead require foreign 

producers to generate RINs for all 

renewable fuel that they export to the 

U.S. We recognize that this would be a 

significant change from RFS1, and thus 

we are not proposing it. However, since 

it would place the same responsibilities 

on foreign producers as domestic 

producers, we request comment on it. 

3. Facilities With Multiple Applicable 

Pathways 

If a given facility’s operations can be 

fully represented by a single pathway, 

then a single D code taken from the 

lookup table will be applicable to all 

RINs generated at or imported into that 

facility. However, we recognize that this 

will not always be the case. Some 

facilities use multiple feedstocks at the 

same time, or switch between different 

feedstocks over the course of a year. A 

facility may be modified to produce the 

same fuel but with a different process, 

or may be modified to produce a 

different type of fuel. Any of these 

situations could result in multiple 

pathways being applicable to a facility, 

and thus there may be more than one D 

code used for various RINs generated at 

the facility. 

If more than one pathway applies to 

a facility within a compliance period, 

no special steps would need to be taken 

if the D codes were the same for all the 

applicable pathways. In this case, all 

RINs generated at the facility would 

have the same D code. As for all other 

producers, the producer with multiple 

applicable pathways would describe its 

feedstock(s), fuel type(s), and 

production process(es) in its annual 

report to the Agency so that we could 

verify that the D code used was 

appropriate. 

However, if more than one pathway 

applies to a facility within a compliance 

period and these pathways have been 

assigned different D codes, then the 

producer must determine which D 

codes to use when generating RINs. 

There are a number of different ways 

that this could occur, and our proposed 

approach to designating D codes for 

RINs in these cases is described in Table 

III.D.3–1. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24949 

26Batch-RINs and gallon-RINs are defined in the 

RFS1 regulations at 40 CFR 80.1101(o). 

TABLE III.D.3–1—PROPOSED APPROACH TO ASSIGNING MULTIPLE D CODES FOR MULTIPLE APPLICABLE PATHWAYS

Case Description Proposed approach 

1 .............................................................. The pathway applicable to a facility changes on a 

specific date, such that one single pathway applies before the date and another single pathway applies on and after the date.

The applicable D code used in generating RINs 

must change on the date that the fuel produced changes pathways. 

2 .............................................................. One facility produces two or more different types 

of renewable fuel at the same time.

The volumes of the different types of renewable 

fuel should be measured separately, with different D codes applied to the separate volumes. 

3 .............................................................. One facility uses two or more different feedstocks 

at the same time to produce a single type of 

renewable fuel.

For any given batch of renewable fuel, the producer should assign the applicable D codes 

using a ratio (explained below) defined by the 

amount of each type of feedstock used. 

In general, we are not aware of a 

scenario in which a facility uses two 

different processes in parallel to convert 

a single type of feedstock into a single 

type of renewable fuel. Therefore, we 

have not created a case in Table III.D.3– 

1 to address it. However, we know that 

some corn-ethanol facilities may dry 

only a portion of their distiller’s grains 

and leave the remainder wet. Using the 

lifecycle with an assumed 100 year 

timeframe and 2% discount rate for 

GHG emission impacts, the treatment of 

the distiller’s grains could impact the 

determination of whether the 20% GHG 

threshold for renewable fuel has been 

met, a corn-ethanol facility that dries 

some portion of its distiller’s grains 

would need to implement additional 

technologies in order to qualify to 

generate RINs for all the ethanol it 

produces (if the facility has not been 

grandfathered). The lifecycle analyses 

conducted for this proposal only 

examined cases in which a corn-ethanol 

facility dried 100% of its distiller’s 

grains or left 100% of its distiller’s 

grains wet. As a result, a corn-ethanol 

facility that dried only a portion of its 

distiller’s grain would be treated as if it 

dried 100% of its grains, and would 

thus need to implement additional 

GHG-reducing technologies as described 

in the lookup table in order to qualify 

to generate RINs. This is reflected in the 

list of required production technologies 

in the lookup table at § 80.1426(d) for 

facilities that dry any portion of their 

distiller’s grains. In practice, depending 

on the selection of other technologies, it 

may be possible for a facility using some 

combination of dry and wet distiller’s 

grains to meet the 20% GHG threshold. 

Therefore we request comment on 

whether a selection of pathways should 

be included in the lookup table that 

represent corn-ethanol facilities that dry 

only a portion of their distiller’s grains. 

We also request comment on whether 

RINs could be assigned to only a portion 

of the facility’s ethanol in cases wherein 

only a portion of the distiller’s grains 

are dried. 

We propose that the cases listed in 

Table III.D.3–1 be treated as 

hierarchical, with Case 2 only being 

used to address a facility’s 

circumstances if Case 1 is not 

applicable, and Case 3 only being used 

to address a facility’s circumstances if 

Case 2 is not applicable. We believe that 

this approach covers all likely cases in 

which multiple applicable pathways 

may apply to a renewable fuel producer. 

Some examples in which Case 2 or 3 

would apply are provided in Table 

III.D.3–2. 

TABLE III.D.3–2—EXAMPLES OF FACILITIES WITH MULTIPLE PATHWAYS

Example Applicable 

case Reasoning 

Facility makes both diesel and naphtha (a gasoline blendstock) 

from gasified biomass in a Fischer-Tropsch process.

2 The production of two types of renewable fuel from the same 

feedstock and process makes it highly likely that the two 

pathways would be assigned the same D code. If LCA determined that this was not the case, the volumes of diesel and 

naphtha can be measured separately and assigned separate 

batch-RINs with different D codes. 

Facility produces ethanol from corn starch and corn cobs/husks 3 There is only one fuel produced, so Case 2 cannot apply. 

Facility makes both ethanol and butanol through two different 

processes using corn starch.

2 Case 2 is the default since there are two separate fuels produced. However, Case 3 would not apply regardless because 

there is only one feedstock. 

Facility makes ethanol through an enzymatic hydrolysis process 

using both switchgrass and corn stover.

3 There is only one fuel produced, so Case 2 cannot apply. 

A facility where two or more different 

types of feedstock were used to produce 

a single fuel (such as Case 3 in Table 

III.D.3–1) would be required to generate 

two or more separate batch-RINs 26 for a 

single volume of renewable fuel, and 

these separate batch-RINs would have 

different D codes. The D codes would be 

chosen on the basis of the different 

pathways as defined in the lookup table 

in § 80.1426(d). The number of gallonRINs that would be included in each of 

the batch-RINs would depend on the 

relative amount of the different types of 

feedstocks used by the facility. We 

propose to use the useable energy 

content of the feedstocks to determine 

how many gallon-RINs should be 

assigned to each D code. Our proposed 

calculations are given in the regulations 

at § 80.1126(d)(5). 

In determining the useable energy 

content of the feedstocks, we propose to 

take into account several elements to 

ensure that the number of gallon-RINs 

associated with each D code is 

appropriate. For instance, we propose 

24950 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

that only that portion of a feedstock 

which is expected to be converted into 

renewable fuel by the facility should be 

counted in the calculation. For example, 

a biochemical cellulosic ethanol 

conversion process that could not 

convert the lignin into ethanol would 

not include the lignin portion of the 

biomass in the calculation. This 

approach would also take into account 

the conversion efficiency of the facility. 

We propose that the producer of the 

renewable fuel would be required to 

designate this fraction for the feedstocks 

processed by his facility and to include 

this information as part of its reporting 

requirements. 

We are also proposing to use the 

energy content of the feedstocks instead 

of their mass since we believe that their 

relative energy contents are more 

closely related than their mass to the 

energy in the renewable fuel. Producers 

would be required to designate the 

energy content (in Btu/lb) of the portion 

of each of their feedstocks which is 

converted into fuel. We request 

comment on whether producers would 

determine these values independently 

for their own feedstocks, or whether a 

standard set of such values should be 

developed and incorporated into the 

regulations for use by all renewable fuel 

producers. If we did specify a standard 

set of energy content values, we request 

comment on what those values should 

be and/or the most appropriate sources 

for determining those values. 

Some components in the calculation 

of the useable energy content of 

feedstocks are unlikely to vary 

significantly for a particular type of 

feedstock. This would include that 

portion of a feedstock which is expected 

to be converted into renewable fuel by 

the facility, and the relative amount of 

energy in the two feedstocks. For these 

factors, we propose that one set of 

values be determined by the producer 

and applied to all renewable fuel 

production within a calendar year. The 

values could be reassessed annually and 

adjusted as necessary. 

Although we are proposing annual 

determinations of the portion of a 

feedstock which is expected to be 

converted into renewable fuel by the 

facility and the relative amount of 

energy in the two feedstocks, we are 

proposing daily determinations of the 

total mass of each type of feedstocks 

used by the facility. This approach 

would take into account the fact that the 

relative amount of the different 

feedstocks used could vary frequently, 

and thus the determination of the total 

useable energy content of the feedstocks 

would be unique to the renewable fuel 

produced each day. We believe that 

renewable fuel producers would have 

ready access to information about total 

feedstock mass used each day, such that 

the timely generation of RINs should not 

be unduly affected. We request 

comment on the effort and time 

involved in collecting information on 

feedstock mass and translating this 

information on a daily basis into RINs 

assigned to volumes of renewable fuel. 

In order to generate RINs when the 

processing of two or more different 

feedstocks in the same facility results in 

two or more different applicable D 

codes but a single renewable fuel, the 

producer would continue to determine 

the total number of gallon-RINs that 

must be generated for and assigned to a 

given volume of renewable fuel using 

the process established under RFS1. In 

short, the total volume of the renewable 

fuel would be multiplied by its 

Equivalence Value. However, the 

feedstock’s useable energy content 

would be used to divide the resulting 

number of gallon-RINs into two or more 

groups, each corresponding to a 

different D code. Two, three, or more 

separate batch-RINs could then be 

generated and assigned to the single 

volume of renewable fuel. The sum of 

all gallon-RINs from the different batchRINs would be equal to the total number 

of gallon-RINs that must be generated to 

represent the volume of renewable fuel. 

As described in Section III.J, we 

propose that in their reports, producers 

of renewable fuel be required to submit 

information on the feedstocks they used, 

their production processes, and the type 

of fuel(s) they produced during the 

compliance period. This would apply to 

both domestic producers and foreign 

producers who export any renewable 

fuel to the U.S. We would use this 

information to verify that the D codes 

used in generating RINs were 

appropriate. 

4. Facilities That Co-Process Renewable 

Biomass and Fossil Fuels 

We expect situations to arise in which 

a producer uses a renewable feedstock 

simultaneously with a fossil fuel 

feedstock, producing a single fuel that is 

only partially renewable. For instance, 

biomass might be cofired with coal in a 

coal-to-liquids (CTL) process that uses 

Fischer-Tropsch chemistry to make 

diesel fuel, biomass and waste plastics 

might be fed simultaneously into a 

catalytic or gasification process to make 

diesel fuel, or vegetable oils could be 

fed to a hydrotreater along with 

petroleum to produce a diesel fuel. In 

these cases, the diesel fuel would be 

only partially renewable. We propose 

that RINs must be generated in such 

cases, but in such a way that the number 

of gallon-RINs corresponds only to the 

renewable portion of the fuel. 

Under RFS1, we created a provision 

to address the co-processing of 

‘‘renewable crudes’’ along with 

petroleum feedstocks to produce a 

gasoline or diesel fuel that is partially 

renewable. See 40 CFR 80.1126(d)(6). 

However, this provision would not 

apply in cases where either the 

renewable feedstock or the fossil fuel 

feedstock is a gas (e.g., biogas, natural 

gas) or a solid (e.g. biomass, coal). 

Therefore, we propose to eliminate the 

existing provision applicable only to 

liquid feedstocks and replace it with a 

more comprehensive approach that 

could apply to liquid, solid, or gaseous 

feedstocks and any type of conversion 

process. Our proposed approach would 

be similar to the treatment of renewable 

fuels with multiple D codes as described 

in Section III.D.3 above. Thus, the 

producer would determine the 

renewable fuel volume that would be 

assigned RINs based on the amount of 

energy in the renewable feedstock 

relative to the amount of energy in the 

fossil feedstock. Just as two different 

batch-RINs would be generated for a 

single volume of renewable fuel 

produced from two different renewable 

feedstocks, only one batch-RIN would 

be generated for a single volume of 

renewable fuel produced from both a 

renewable feedstock and a fossil 

feedstock, and this one batch-RIN would 

be based on the contribution that the 

renewable feedstock makes to the 

volume of renewable fuel. See 

§ 80.1426(d)(6) for our proposed 

calculations under these circumstances. 

For facilities that co-process 

renewable biomass and fossil fuels to 

produce a single fuel that is partially 

renewable, we propose to use the 

relative energy in the feedstocks to 

determine the number of gallon-RINs 

that should be generated. As shown in 

the regulations at § 80.1426(d)(6), the 

calculation of the relative energy 

contents would include factors that take 

into account the conversion efficiency 

of the plant, and as a result, potentially 

different reaction rates and byproduct 

formation for the various feedstocks 

would be accounted for. The relative 

energy content of the feedstocks would 

be used to adjust the basic calculation 

of the number of gallon-RINs downward 

from that calculated on the basis of fuel 

volume alone. The D code that would be 

assigned to the RINs would be drawn 

from the lookup table in the regulations 

as if the feedstock was entirely 

renewable biomass. Thus, for instance, 

a coal-to-liquids plant that co-processes 

some cellulosic biomass to make diesel 

fuel would be treated as a plant that 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24951 

27Additional default requirements applicable to 

importers of renewable fuels are discussed in 

Section III.D.2.c. 

produces only cellulosic diesel for 

purposes of identifying the appropriate 

D code. 

One drawback of our proposed 

approach is that it does nothing to 

address lifecycle GHG emissions 

associated with the portion of the fuel 

that comes from the fossil fuel 

feedstock. While the lifecycle GHG 

thresholds under RFS2 are specific to 

fuels made from renewable biomass, 

allowing a fuel producer to generate 

RINs for the co-processing of renewable 

biomass with fossil fuels might provide 

a greater incentive for production of 

transportation fuels from processes that 

have high lifecycle GHGs. In such cases, 

the GHG benefits of the renewable fuel 

may be overwhelmed by the GHG 

increases of the fossil fuel. This is of 

particular concern for CTL processes 

which generally produce higher 

lifecycle GHG emissions per unit of 

transportation fuel produced than 

traditional refinery processes that use 

petroleum. Under our proposed 

approach to the treatment of coprocessing of renewable biomass and 

fossil fuels, incentives would be 

provided for renewable fuels with lower 

lifecycle GHG emissions, but there will 

be little disincentive for production of 

high GHG-emitting fuels made from 

fossil fuels. 

As an alternative to our proposed 

approach, we could treat fuels produced 

through co-processing of renewable 

biomass and fossil fuel feedstocks in an 

aggregate fashion rather than focusing 

only on the renewable portion of those 

fuels. In this approach, we would 

require the whole fuel produced at coprocessing facilities to meet the lifecycle 

GHG thresholds under RFS2. If, for 

instance, a diesel fuel produced from 

co-processing renewable biomass and 

coal in a Fischer-Tropsch process were 

determined to not meet the 20% GHG 

threshold, no RINs could be generated 

even though the renewable portion of 

the diesel fuel might meet the 20% GHG 

threshold. However, this alternative 

approach would require a lifecycle 

analysis that is specific to the relative 

amounts of renewable biomass and 

fossil fuel feedstock being used at a 

particular facility, which would in turn 

require a facility-specific lifecycle GHG 

model. As described in Section II.A.3, 

this is beyond the capabilities of our 

current modeling tools. Moreover, this 

alternative approach could have 

undesirable effects on facilities that 

produce renewable fuel from multiple 

renewable feedstocks. For instance, if a 

facility produced ethanol from both 

corn starch and corn stover and the 

lifecycle GHG assessment was 

conducted for this specific facility as a 

whole, it might not meet the 60% GHG 

threshold for cellulosic biofuel. As a 

result, the portion of the ethanol 

produced from corn stover could not be 

counted as cellulosic biofuel but would 

instead count only as renewable fuel, 

even though our lifecycle analyses have 

determined that ethanol from corn 

stover does meet the 60% GHG 

threshold. Nevertheless, we seek 

comment on this alternative approach. 

As another alternative to using the 

relative energy in the feedstocks to 

determine the number of gallon-RINs 

that should be generated, we could 

allow renewable fuel producers to use 

an accepted test method to directly 

measure the fraction of the fuel which 

originates with biomass rather than a 

fossil fuel feedstock. For instance, 

ASTM test method D–6866 can be used 

to determine the renewable content of 

gasoline. However, such a test method 

could not distinguish between fuel 

made from feedstocks that meet the 

definition of renewable biomass, and 

other biomass feedstocks which do not 

meet the definition of renewable 

biomass. We request comment on the 

use of ASTM D–6866 or equivalent test 

methods to determine the number of 

RINs generated when multiple 

feedstocks are used simultaneously to 

make a fuel. 

5. Treatment of Fuels Without an 

Applicable D Code 

Among all fuels covered by our 

proposed RFS2 program, we have 

identified a number of specific 

‘‘pathways’’ of fuels, defined by fuel 

type, feedstock, and various production 

process characteristics. This list 

includes fuels that either already exist 

in the marketplace or are expected to 

exist sometime during the next decade, 

and for which we had sufficient 

information to conduct a lifecycle 

analysis of the GHG emissions. As 

described in III.D.2, we have assigned 

each pathway a D code corresponding to 

the four categories of renewable fuel 

defined in EISA. 

Despite our efforts to explicitly 

address the existing or possible 

pathways in our proposed program, it is 

expected that a fuel, process, or 

feedstock will arise that is a renewable 

fuel meeting the RFS definitions, and 

yet is not among the fuels we explicitly 

identified in the regulations as a RINgenerating fuel. This could occur for an 

entirely new fuel type, a known fuel 

produced from a new feedstock, or a 

known fuel produced through a unique 

production process. In such cases, the 

fuel may meet our definition of 

renewable fuel covered under our 

program, but would not have been 

assigned the appropriate D code in the 

regulations. To address some of these 

fuel pathways, we are proposing the use 

of default D codes.27

Under our proposed approach, the 

producer would be required to register 

under the RFS program and provide 

information about their facility as 

described in Section III.C. The producer 

will also be required to provide any 

information necessary for EPA to 

perform a proper lifecycle analysis. 

Additionally, the company would need 

to register their renewable fuel under 

title 40 CFR part 79 as a motor vehicle 

fuel. If EPA determines, based on the 

company’s registration, that they are not 

producing renewable fuel, the company 

will not be able to generate RINs. 

In order to generate RINs, the 

producer of renewable fuel would apply 

through our registration system to use 

the D code that best represents his 

combination of fuel type, feedstock, and 

production process. If the producer’s 

combination of fuel type and feedstock, 

but not production process, is 

represented in an already defined 

pathway combination of fuels, 

processes, or feedstocks, the producer 

would use the highest numerical D code 

applicable to the fuel and feedstock 

combination. For example, if a fuel and 

feedstock spans the D Codes 3 and 4 

then the producer would use 4 until the 

regulations were updated. The producer 

then would generate RINs using the D 

code 4, until EPA could perform a 

lifecycle analysis and issue a change to 

the regulations to reflect the new 

pathway. If the producer is making a 

new fuel or using a new feedstock that 

producer will still need to apply, but 

would be unable to generate RINs until 

the regulations were updated with the 

new pathway. 

Since certain combinations of fuel, 

production process, and feedstock have 

been determined through our lifecycle 

analysis to not meet the minimum 20% 

GHG threshold, they would be ineligible 

to generate RINs and EPA would not 

allow producers using those processes 

to generate RINs using a default D code. 

To effectuate this, we propose to 

provide a statement in the regulations of 

pathways that are prohibited from using 

a default D code. For example, if a 

producer is producing ethanol from 

cornstarch in a process that uses coal or 

natural gas for process heat, then 

regardless of other elements of the 

production process the producer may 

not use a default D code, but must 

register and provide information 

24952 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

28More information on the EPA’s UIC Program 

and ongoing research into CCS issues is available 

at: http://www.epa.gov/safewater/uic/ 

wells_sequestration.html. 

necessary to conduct a lifecycle 

analysis. 

EPA will not conduct a rulemaking 

every year to adjust the regulations for 

new fuels, processes, or feedstocks. EPA 

will periodically update the regulations 

as necessary under CAA section 

211(o)(4) and may take the opportunity 

to update the list of fuel pathways. 

Companies are encouraged to work with 

EPA early to provide information about 

fuels, processes, or feedstocks not in the 

regulations so that we can do a proper 

lifecycle analysis before these fuels, 

processes, or feedstocks are 

commercially viable. EPA is proposing 

that if the regulations are not updated 

with in 5 years of receipt of the 

application and the application is not 

rejected in that time then the producer 

will no longer be able to generate RINs 

using a default D code until the 

regulations are updated. 

6. Carbon Capture and Storage (CCS) 

One element of the production 

process that may enable renewable fuel 

producers to greatly improve their GHG 

emissions is carbon capture and storage 

(CCS). CCS involves the process of 

capturing CO2 from an industrial or 

energy-related source, transporting it to 

a suitable storage site, and isolating it 

from the atmosphere for long periods of 

time. While we are not proposing a 

specific pathway in today’s NPRM that 

would allow a renewable fuel producer 

to use CCS to demonstrate compliance 

with the GHG thresholds, we believe 

that CCS could be an effective method 

for significantly reducing the GHG 

emissions associated with renewable 

fuel production. 

Although there are several possible 

approaches for long-term storage of CO2, 

this section will only address geologic 

storage as a means to reduce CO2

emissions from renewable fuel 

production facilities. This method 

entails injecting CO2 deep underground 

and monitoring to ensure long-term 

isolation from the atmosphere. The 

remainder of this section describes the 

efforts to establish regulatory 

requirements for CCS, and the further 

work that needs to be done before 

allowing the use of CCS as an element 

in pathways eligible for generating RINs 

under the RFS2 program. 

Although there is limited experience 

with integrated CCS systems in the US, 

where CO2 is captured, transported and 

injected for long-term storage, there are 

commercial CCS projects operating 

today and several DOE pilot projects 

underway to further demonstrate CCS in 

a variety of industrial sectors and 

geological settings. The EPA has been 

working closely with DOE to 

collectively ensure that governmental 

research programs address the range of 

potential environmental risks associated 

with CCS and that appropriate 

regulatory frameworks are in place to 

manage risks.28

The EPA has experience regulating 

underground injection of various fluids 

and believes that well selected, 

designed, and managed sites can 

sequester CO2 for long periods of time. 

The Safe Drinking Water Act’s (SDWA) 

Underground Injection Control (UIC) 

Program has been successfully 

regulating tens of thousands of injection 

wells for over 35 years. The UIC 

program’s siting, well construction, and 

monitoring and testing requirements are 

keys to ensuring that injected fluids 

remain in the geologic rock formations 

specifically targeted for injection. 

In March 2007, the EPA issued UIC 

permitting guidelines for pilot geologic 

sequestration projects in order to ensure 

that these projects could move forward 

under an appropriate regulatory 

framework. Subsequently, on July 25, 

2008, EPA issued a proposed 

rulemaking that would address 

commercial-scale projects and establish 

the regulatory requirements for 

underground injection of CO2 for the 

purpose of geologic storage (73 FR 

43492). These proposed regulations 

include permitting requirements, 

criteria for establishing and maintaining 

the mechanical integrity of wells, 

minimum criteria for siting, injection 

well construction and operating 

requirements, recordkeeping and 

reporting requirements, etc. While these 

regulations cover many operational 

aspects of underground injection and 

monitoring geologic sequestration sites, 

their purpose is to protect underground 

sources of drinking water. The SDWA 

does not provide authority to develop 

regulations for all areas related to CCS, 

including capture and transport of CO2

and accounting or certification for GHG 

emissions reductions. The UIC 

requirements will not replace or 

supersede other statutory or regulatory 

requirements for protection of human 

health and the environment. Thus, 

parties that implemented CCS would 

still need to obtain all necessary permits 

from appropriate State and Federal 

authorities under the Clean Air Act or 

any other applicable statutes and 

regulations. 

Specific areas that would need to be 

addressed before allowing the 

renewable fuel producers to benefit 

from CCS in meeting GHG thresholds 

include: the means through which the 

CO2 would be captured from the 

renewable fuel production facility, the 

minimum fraction that must be 

captured, appropriate means for 

transporting to the injection site, and 

appropriate monitoring procedures to 

ensure long-term storage of CO2. We 

believe the CO2 that would be most 

readily available for capture in an 

ethanol production facility would be 

that which is produced during the 

fermentation process, not CO2 that is 

generated during the combustion of 

fossil fuels for process energy, since CO2

from the fermentation process provides 

a more concentrated stream that is more 

amenable to capture. However, we 

request comment on the efficacy of 

capturing CO2 from the combustion of 

fossil fuels for process heat. 

A mechanism for accounting for 

potential leakage of captured CO2

during transport to the storage site or 

after injection has occurred would also 

be required. The renewable fuel 

producer would be responsible for 

tracking any leaks that occur after CO2

capture. We request comment on the 

type and level of surface and/or 

subsurface monitoring that would be 

required to demonstrate long-term 

storage of CO2. We also request 

comment on whether additional 

monitoring and reporting requirements 

would be appropriate. For example, 

whether there should be a requirement 

for the monitoring and reporting of CO2

volumes captured, transported, injected 

and stored, as well as any fugitive 

emissions released. We seek comment 

on the appropriateness of establishing a 

performance standard for CO2 leakage 

during transport, injection, and/or 

geologic storage, and any data that 

might be available to help develop such 

a performance standard. 

Finally, in order to generate RINs, the 

renewable fuel producer would have to, 

at minimum, demonstrate that a 

sufficient amount of CO2 was 

sequestered to reach the appropriate 

lifecycle GHG threshold. We expect that 

the regulations would need to specify 

the minimum fraction of CO2 emitted 

that must be captured and stored in 

order for a renewable fuel producer to 

qualify for generating RINs. We request 

comment on whether this approach is 

appropriate. 

E. Applicable Standards 

CAA section 211(o)(3) describes how 

the applicable standards are to be 

calculated. The only changes made to 

this provision by EISA are substituting 

‘‘transportation fuel’’ for gasoline, and 

reflecting the expanded number of years 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24953 

29Actual volumes can vary from the amounts 

required in the statute. For instance, lower volumes 

may result if the statutorily required volumes are 

adjusted downward according to the waiver 

provisions in CAA 211(o)(7)(D). Also, higher or 

lower volumes may result depending on the actual 

consumption of gasoline and diesel in comparison 

to the projected volumes used to set the standards. 

30Hawaii opted-in to the original RFS program; 

that opt-in is carried forward to the proposed new 

program. 

and additional renewable fuel categories 

added by Congress in CAA 211(o)(2). In 

general the form of the standard will not 

change under RFS2. The renewable fuel 

standards will continue to be expressed 

as a volume percentage, and will be 

used by each refiner, blender or 

importer to determine their renewable 

volume obligations. The applicable 

percentages are set so that if each 

regulated party meets the percentages, 

then the amount of renewable fuel, 

cellulosic biofuel, biomass-based diesel, 

and advanced biofuel used will meet the 

volumes specified in Table II.A.1–1.29

The new renewable fuel standards 

would be based on both gasoline and 

diesel volumes as opposed to only 

gasoline. Under CAA section 211(o)(3), 

EPA must determine the refiners, 

blenders and importers who are subject 

to the standard. We propose that the 

standard would apply to refiners, 

blenders and importers of diesel in 

addition to gasoline, for both highway 

and nonroad uses. As described more 

fully in Section III.F.3, we are proposing 

at this time that other producers of 

transportation fuel, such as producers of 

natural gas, propane, and electricity 

from fossil fuels, would not be subject 

to the standard. Since the standard 

would apply to refiners, blenders and 

importers of gasoline and diesel, these 

are also the transportation fuels that 

would be used to determine the annual 

volume obligation of the refiner, blender 

or importer. 

The projected volumes of gasoline 

and diesel used to calculate the 

standards would continue to be 

provided by EIA’s Short-Term Energy 

Outlook (STEO). The standards 

applicable to a given calendar year 

would be published by November 30 of 

the previous year. The renewable fuel 

standards would also continue to take 

into account various adjustments. For 

instance, gasoline and diesel volumes 

would be adjusted to account for the 

required renewable fuel volumes, and 

gasoline and diesel volumes produced 

by small refineries and small refiners 

would continue to be exempt through 

2010. 

While the calculation methodology 

for determination of standards would 

not change, there would be four separate 

standards under the new RFS2 program, 

corresponding to the four separate 

volume requirements shown in Table 

II.A.1–1. The specific formulas we 

propose using to calculate the 

renewable fuel standards are described 

below in Section III.E.1. 

In order for an obligated party to 

demonstrate compliance, the percentage 

standards would be converted into the 

volume of renewable fuel each obligated 

party is required to satisfy. This volume 

of renewable fuel is the volume for 

which the obligated party is responsible 

under the RFS program, and would 

continue to be referred to as its 

Renewable Volume Obligation (RVO). 

Since there would be four separate 

standards under the RFS2 program, 

there would likewise be four separate 

RVOs applicable to each refiner, 

importer, or other obligated party. 

However, all RVOs would be 

determined in the same way as 

described in the current regulations at 

§ 80.1107, with the exception that each 

standard would apply to the sum of all 

gasoline and diesel produced or 

imported as opposed to just the gasoline 

volume. The formulas we propose using 

to calculate the RVOs under the RFS2 

program are described in Section III.G.1. 

1. Calculation of Standards 

a. How Would the Standards Be 

Calculated? 

Table II.A.1–1 shows the required 

overall volumes of four types of 

renewable fuel specified in EISA. The 

four separate renewable fuel standards 

would be based primarily on (1) the 49- 

state 30 gasoline and diesel consumption 

volumes projected by EIA, and (2) the 

total volume of renewable fuels required 

by EISA for the coming year. Each 

renewable fuel standard will be 

expressed as a volume percentage of 

combined gasoline and diesel sold or 

introduced into commerce in the U.S., 

and will be used by each obligated party 

to determine its renewable volume 

obligation. 

While we are proposing that the 

standards be based on the sum of all 

gasoline and diesel, an alternative 

would split the standards between those 

that would be specific to gasoline and 

those that would be specific to diesel. 

To accomplish this, it would be 

necessary to project the fraction of the 

volumes shown in Table II.A.1–1 for 

cellulosic biofuel, advanced biofuel, and 

total renewable fuel that would 

represent gasoline-displacing renewable 

fuel, and apply this portion of the 

required volumes to gasoline (by 

definition the biomass-based diesel 

standard would have no component 

relevant to gasoline). The remaining 

portion would apply to diesel. The 

result would be seven standards instead 

of four. This approach to setting 

standards would more readily align the 

RFS obligations with the relative 

amounts of gasoline and diesel 

produced or imported by each obligated 

party. For instance, a refiner that 

produced only diesel fuel would have 

no obligations under the RFS program 

for renewable fuels that are used to 

displace gasoline. However, this 

alternative approach relies on 

projections of the relative amounts of 

gasoline-displacing and dieseldisplacing renewable fuels that would 

need to be updated every year. While 

such projections would be available 

through our proposed Production 

Outlook Reports (see Section III.K), we 

nevertheless believe that such an 

approach would unnecessarily 

complicate the program, and thus we 

are not proposing it. However, we 

request comment on it. 

In determining the applicable 

percentages for a calendar year, EISA 

requires EPA to adjust the standard to 

prevent the imposition of redundant 

obligations on any person and to 

account for renewable fuel use during 

the previous calendar year by exempt 

small refineries, defined as refineries 

that process less than 75,000 bpd of 

crude oil. As a result, in order to be 

assured that the percentage standards 

will in fact result in the volumes shown 

in Table II.A.1–1, we must make several 

adjustments to what otherwise would be 

a simple calculation. 

As stated, the renewable fuel 

standards for a given year are basically 

the ratio of the amount of each type of 

renewable fuel specified in EISA for that 

year to the projected 49-state nonrenewable combined gasoline and diesel 

volume for that year. While the required 

amount of total renewable fuel for a 

given year is provided by EISA, the Act 

requires EPA to use an EIA estimate of 

the amount of gasoline and diesel that 

will be sold or introduced into 

commerce for that year to determine the 

percentage standards. The levels of the 

percentage standards would be reduced 

if Alaska or a U.S. territory chooses to 

participate in the RFS2 program, as 

gasoline and diesel produced in or 

imported into that state or territory 

would then be subject to the standard. 

As mentioned above, we are 

proposing that EIA’s STEO continue to 

be the source for projected gasoline, and 

now diesel, consumption estimates. 

These volumes include renewable fuel 

use. In order to achieve the volumes of 

renewable fuels specified in EISA, the 

gasoline and diesel volumes used to 

24954 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

31Under section 211(o) of the Clean Air Act, 

small refineries are those with 75,000 bbl/day or 

less average aggregate daily crude oil throughput. 

32See Section IV.B.2. 

determine the standard must be the nonrenewable portion of the gasoline and 

diesel pools. In order to get total nonrenewable gasoline and diesel volumes, 

we must subtract the total renewable 

fuel volume from the total gasoline and 

diesel volume. As with RFS1, the best 

estimation of the coming year’s 

renewable fuel consumption is found in 

Table 11 (U.S. Renewable Energy Use by 

Sector: Base Case) of the STEO. 

CAA section 211(o) exempts small 

refineries 31 from the RFS requirements 

until the 2011 compliance period. In 

RFS1, we extended this exemption to 

the few remaining small refiners not 

already exempted.32 Since EPA 

proposes that small refineries and small 

refiners continue to be exempt from the 

program until 2011 under the new RFS2 

regulations, EPA will exclude their 

gasoline and diesel volumes from the 

overall non-renewable gasoline and 

diesel volumes used to determine the 

applicable percentages until 2011. EPA 

believes this is appropriate because the 

percentage standards need to be based 

on the gasoline and diesel subject to the 

renewable volume obligations, to 

achieve the overall required volumes of 

renewable fuel. Because the total small 

refinery and small refiner gasoline 

production volume is expected to be 

fairly constant compared to total U.S. 

transportation fuel production, we are 

proposing to estimate small refinery and 

small refiner gasoline and diesel 

volumes using a constant percentage of 

national consumption, as we did in 

RFS1. Using information from gasoline 

batch reports submitted to EPA for 2006, 

EIA data, and input from the California 

Air Resources Board regarding 

California small refiners, we estimate 

that small refinery volumes constitute 

11.9% of the gasoline pool, and 15.2% 

of the diesel pool. 

CAA section 211(o) requires that the 

small refinery adjustment also account 

for renewable fuels used during the 

prior year by small refineries that are 

exempt and do not participate in the 

RFS2 program. Accounting for this 

volume of renewable fuel would reduce 

the total volume of renewable fuel use 

required of others, and thus 

directionally would reduce the 

percentage standard. However, as we 

discussed in RFS1, the amount of 

renewable fuel that would qualify, i.e., 

that was used by exempt small 

refineries and small refiners but not 

used as part of the RFS program, is 

expected to be very small. In fact, these 

volumes would not significantly change 

the resulting percentage standards. 

Whatever renewable fuels small 

refineries and small refiners blend will 

be reflected as RINs available in the 

market; thus there is no need for a 

separate accounting of their renewable 

fuel use in the equations used to 

determine the standards. We thus are 

proposing, as for RFS1, that this value 

be zero. 

Just as with their corresponding 

gasoline and diesel volumes, renewable 

fuels used in Alaska or U.S. territories 

are not included in the renewable fuel 

volumes that are subtracted from the 

total gasoline and diesel volume 

estimates. Section 211(o) of the Clean 

Air Act requires that the renewable fuel 

be consumed in the contiguous 48 

states, and any other state or territory 

that opts in to the program (Hawaii has 

subsequently opted in). However, 

because renewable fuel produced in 

Alaska or a U.S. territory is unlikely to 

be transported to the contiguous 48 

states or to Hawaii, including their 

renewable fuel volumes in the 

calculation of the standard would not 

serve the purpose intended by section 

211(o) of the Clean Air Act of ensuring 

that the statutorily required renewable 

fuel volumes are consumed in the 48 

contiguous states and any state or 

territory that opts in. 

In summary, we are proposing that 

the total projected non-renewable 

gasoline and diesel volumes from which 

the annual standards are calculated be 

based on EIA projections of gasoline and 

diesel consumption in the contiguous 

48 states and Hawaii, adjusted by 

constant percentages of 11.9% and 

15.2% in 2010 to account for small 

refinery/refiner gasoline and diesel 

volumes, respectively, and with built-in 

correction factors to be used when and 

if Alaska or a territory opt-in to the 

program. If actual gasoline and diesel 

consumption were to exceed the EIA 

projections, the result would be that 

renewable fuel volumes would exceed 

the statutory volumes. Conversely, if 

actual gasoline and diesel consumption 

was less than the EIA projection for a 

given year, actual renewable fuel 

volumes could be lower than the 

statutory volumes depending on market 

conditions. Additional special 

considerations in establishing the 

annual cellulosic biofuel standard are 

discussed below in Section III.E.1.c. 

The following formulas will be used 

to calculate the percentage standards: 

Std 100%

RFV

CB, i

CB, i = × ( ) G RG GS RGS GE D RD DS i i i i ii i i − + − ( ) − +− ( ) + ( ) − RDS DE i i −

Std 100%

RFV

BBD, i

BBD, i = × ( ) G RG GS RGS GE D RD D i i i i ii i − + − ( ) − +− ( ) + ( ) S RDS DE i ii − −

Std 100%

RFV

AB, i

AB, i = × ( ) G RG GS RGS GE D RD DS i i i i ii i i − + − ( ) − +− ( ) + ( ) − RDS DE i i −

Std 100%

RFV

RF, i

RF, i = × ( ) G RG GS RGS GE D RD DS i i i i ii i i − + − ( ) − +− ( ) + ( ) − RDS DE i i −


EN26MY09.000</MATH> EN26MY09.001</MATH> EN26MY09.002</MATH> EN26MY09.003</MATH>
Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24955 

33 ‘‘Calculation of the Renewable Fuel Standard 

for Gasoline and Diesel,’’ memo to the docket from 

Christine Brunner, ASD, OTAQ, EPA, April 2009. 

Where 

StdCB,i = The cellulosic biofuel standard for 

year i, in percent 

StdBBD,i = The biomass-based diesel standard 

for year i, in percent 

StdAB,i = The advanced biofuel standard for 

year i, in percent 

StdRF,i = The renewable fuel standard for year 

i, in percent 

RFVCB,i = Annual volume of cellulosic 

biofuel required by section 211(o)(2)(B) 

of the Clean Air Act for year i, in gallons 

RFVBBD,i = Annual volume of biomass-based 

diesel required by section 211(o)(2)(B) of 

the Clean Air Act for year i, in gallons 

RFVAB,i = Annual volume of advanced 

biofuel required by section 211(o)(2)(B) 

of the Clean Air Act for year i, in gallons 

RFVRF,i = Annual volume of renewable fuel 

required by section 211(o)(2)(B) of the 

Clean Air Act for year i, in gallons 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons* 

Di = Amount of diesel projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons 

RGi = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons 

RDi = Amount of renewable fuel blended into 

diesel that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons 

GSi = Amount of gasoline projected to be 

used in Alaska or a U.S. territory in year 

i if the state or territory opts in, in 

gallons* 

RGSi = Amount of renewable fuel blended 

into gasoline that is projected to be 

consumed in Alaska or a U.S. territory in 

year i if the state or territory opts in, in 

gallons 

DSi = Amount of diesel projected to be used 

in Alaska or a U.S. territory in year i if 

the state or territory opts in, in gallons* 

RDSi = Amount of renewable fuel blended 

into diesel that is projected to be 

consumed in Alaska or a U.S. territory in 

year i if the state or territory opts in, in 

gallons 

GEi = The amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons, in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. Equivalent to 

0.119 * (Gi ¥ RGi). 

DEi = The amount of diesel projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons, in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. Equivalent to 

0.152 * (Di ¥ RDi). 

* Note that these terms for projected 

volumes of gasoline and diesel use include 

gasoline and diesel that has been blended 

with renewable fuel. 

b. Proposed Standards for 2010 

In today’s NPRM we are proposing the 

specific standards that would apply to 

all obligated parties in calendar year 

2010. We will consider comments 

received on these standards as part of 

the comment period associated with 

today’s NPRM, and we intend to issue 

a Federal Register notice by November 

30, 2009 setting the applicable 

standards for 2010. While we are not 

proposing standards for 2011 and 

beyond, we present our current 

projections of these standards in the 

next section. 

Under CAA section 211(o)(7)(D)(i), 

EPA is required to make a determination 

each year regarding whether the 

required volumes of cellulosic biofuel 

for the following year can be produced. 

For any calendar year for which the 

projected volume of cellulosic biofuel 

production is less than the minimum 

required volume, the projected volume 

becomes the basis for the cellulosic 

biofuel standard. In such a case, the 

statute also indicates that EPA may also 

lower the required volumes for 

advanced biofuel and total renewable 

fuel. 

Based on information available to 

date, we believe that there are sufficient 

plans underway to build plants capable 

of producing 0.1 billion gallons of 

cellulosic biofuel in 2010, the minimum 

volume of cellulosic biofuel required by 

EISA for 2010. Our April 2009 industry 

assessment concludes that there could 

be seven small commercial-scale plants 

online in 2010 (as well as a series of 

pilot and demonstration plants) capable 

of producing just over 100 million 

gallons of cellulosic biofuel. And since 

the majority of this production (73%) is 

projected to be cellulosic diesel, the 

ethanol-equivalent complaince volume 

could be closer to 145 million gallons. 

While it is possible that some of these 

plants could be delayed or a portion of 

the projected production may not meet 

the definition of ‘‘cellulosic biofuel’’ 

(due to mixed feedstocks), it is also 

possible that other plans could proceed 

ahead of their current schedules. For 

more on the 2010 cellulosic biofuel 

production assessment, refer to Section 

1.5.3.4 of the DRIA 

On the basis of this information, we 

are not proposing that any portion of the 

cellulosic biofuel requirement for 2010 

be waived. Therefore, we are proposing 

that the volumes shown in Table II.A.1– 

1 be used as the basis for the applicable 

standards for 2010. As described more 

fully in Section III.E.2 below, we are 

also proposing that the 2010 standard 

for biomass-based diesel be based on the 

combined required volumes for 2009 

and 2010, or a total of 1.15 billion 

gallons. The proposed standards for 

2010 are shown in Table III.E.1.b–1. 

TABLE III.E.1.b–1—PROPOSED

STANDARDS FOR 2010 

[Percent] 

Cellulosic biofuel ............................... 0.06 

Biomass-based diesel ...................... 0.71 

Advanced biofuel .............................. 0.59 

Renewable fuel ................................. 8.01 

As described more fully in Section 

III.E.1.d below, we are proposing that 

the RFS2 program take effect on January 

1, 2010, but we are also taking comment 

on an effective date later than January 

1, 2010, including January 1, 2011 and 

a mid-2010 effective date. If the RFS2 

program became effective mid-2010, the 

RFS1 program would apply during the 

first part of 2010 and the RFS2 program 

would apply for the remainder of the 

year. We request comment on whether 

the four proposed standards shown in 

Table III.E.1.b–1 would apply only to 

gasoline and diesel produced or 

imported after the RFS2 effective date or 

should apply to all gasoline and diesel 

produced in 2010. We also request 

comment on whether a single standard 

for total renewable fuel should apply 

under RFS1 regulations for the first part 

of 2010. 

c. Projected Standards for Other Years 

As discussed above, we intend to set 

the percentage standards for each 

upcoming year based on the most recent 

EIA projections, and using the other 

sources of information as noted above. 

We would publish the standard in the 

Federal Register by November 30 of the 

preceding year. The standards would be 

used to determine the renewable 

volume obligations based on an 

obligated party’s total gasoline and 

diesel production or import volume in 

a calendar year, January 1 through 

December 31. An obligated party will 

calculate its Renewable Volume 

Obligations (discussed in Section 

III.G.1) using the annual standards. 

For illustrative purposes, we have 

estimated the standards for 2011 and 

later based on current information using 

the formulas discussed above, and 

assuming no modifications to the 

annual volumes required.33 These 

values are listed below in Table III.E.1.c1. The required renewable fuel volumes 

specified in EISA are shown in Table 

II.A.1–1. The projected gasoline, diesel 

and renewable fuels volumes were 

determined from EIA’s energy 

projections. Variables related to Alaska 

or territory opt-ins were set to zero since 

we do not have any information related 

24956 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

to their participation at this time. No 

adjustment was made for small refiner 

or small refinery volumes since their 

exemption is assumed to end at the end 

of the 2010 compliance period. 

TABLE III.E.1.c–1—PROJECTED STANDARDS UNDER RFS2 

[percent] 

Cellulosic 

biofuel 

Biomassbased 

diesel 

Advanced 

biofuel 

Renewable 

fuel 

2011 ................................................................................................................................. 0.15 0.49 0.83 8.60 

2012 ................................................................................................................................. 0.31 0.61 1.22 9.31 

2013 ................................................................................................................................. 0.61 0.61a 1.68 10.09 

2014 ................................................................................................................................. 1.07 0.61a 2.28 11.05 

2015 ................................................................................................................................. 1.83 0.61a 3.35 12.48 

2016 ................................................................................................................................. 2.58 0.61a 4.40 13.49 

2017 ................................................................................................................................. 3.34 0.61a 5.46 14.56 

2018 ................................................................................................................................. 4.25 0.61a 6.68 15.80 

2019 ................................................................................................................................. 5.19 0.61a 7.95 17.11 

2020 ................................................................................................................................. 6.47 0.62a 9.25 18.50 

2021 ................................................................................................................................. 8.40 0.62a 11.21 20.54 

2022 ................................................................................................................................. 10.07 0.63a 13.21 22.65 

aThese projected standards represent the minimum volume of 1.0 billion gallons required by EISA. The actual volume used to set the standard 

would be determined by EPA through a future rulemaking. 

d. Alternative Effective Date 

Although we are proposing that the 

RFS2 regulatory program begin on 

January 1, 2010 which, depending on 

timing for the final rule, would allow 

approximately two months from the 

anticipated issuance of the rule to its 

implementation, we seek comment on 

whether an effective date later than 

January 1, 2010 would be necessary. If 

the RFS2 program was not made 

effective on January 1, 2010, the most 

straightforward alternative start date 

would be January 1, 2011. Delaying to 

2011 would provide regulated parties 

additional lead time and would allow 

all the new requirements and standards 

to go into effect at the beginning of an 

annual compliance period. However, 

delaying to 2011 would also mean that 

demonstrating compliance with the 

separate requirements for biomass-based 

diesel, cellulosic biofuel, and advanced 

biofuel mandates would not go into 

effect until 2011. The total renewable 

fuel mandate in EISA may be able to be 

implemented with the RFS1 regulations 

until such time as the RFS2 regulations 

become effective. However, under the 

RFS1 regulations, this entire standard 

would be for conventional biofuels and 

would be applied to gasoline producers 

and importers only. There would be no 

obligation with respect to diesel fuel 

producers and importers, resulting in a 

numerically larger standard that would 

apply to gasoline producers only and 

which could compel them to market a 

larger proportion of ethanol as E85 to 

acquire sufficient RINs for compliance. 

One possible way to address this issue 

would be to reduce the 2010 total 

renewable fuel standard proportionately 

to reflect the application of the standard 

only to gasoline producers. However, it 

does not appear that EPA has statutory 

authority, or discretion under the RFS1 

regulations, to modify the total 

renewable fuel mandate in this manner. 

As discussed below in Section III.E.2, 

any delay beyond January 1, 2010 also 

has implications for our proposed 

treatment of the biomass-based diesel 

volumes required for 2009. EPA invites 

comment on whether RFS2 

implementation should be delayed to 

January 1, 2011 and, if so, the manner 

in which the EISA-mandated RFS 

program should be implemented prior 

to that date. 

Another alternative would be to delay 

the effective date of the RFS2 program 

to some time after January 1, 2010 but 

before January 1, 2011. This alternative 

would raise the same issues described 

above (regarding the option of a delay 

until January 1, 2011) for that portion of 

2010 during which RFS2 was not 

effective. It would also raise additional 

transition and implementation issues. 

For instance, we would need to 

determine whether diesel fuel producers 

and importers carry a total renewable 

fuel obligation calculated on the basis of 

their production for all of 2010 or just 

the production period in 2010 during 

which the RFS2 regulations are 

effective. We would also need to 

determine whether the 2010 cellulosic 

biofuel, biomass-based diesel, and 

advanced biofuel standards applicable 

under RFS2 should apply to production 

of gasoline and diesel for all of 2010 or 

just the production that occurred after 

the RFS2 regulations were effective If 

the latter, EPA would need to determine 

the extent to which RFS1 RINs 

generated in the first part of 2010 could 

be used to satisfy RFS2 obligations, 

given that some 2010 RINs would be 

generated under the RFS1 requirements 

while other 2010 RINs would be 

generated under RFS2 requirements. To 

accomplish this, RINs generated under 

the RFS2 requirements would need to 

be distinguished from RINs generated 

under RFS1 requirements through the 

RINs’ D codes. Section III.A provides a 

more detailed description of this 

alternative approach to the assignment 

of D codes under the RFS2 program. For 

additional discussion of how RFS1 RINs 

would be treated in the transition to the 

RFS2 program, see our proposed 

transition approach described in Section 

III.G.3. 

We are requesting comment on all 

issues related to the option of an RFS2 

start date sometime after January 1, 

2010, including the need for such a 

delayed start, the level of the standards, 

treatment of diesel producers and 

importers, whether the standards for 

advanced biofuel, cellulosic biofuel and 

biomass-based diesel should apply to 

the entire 2010 production or just the 

production that would occur after the 

RFS2 effective date, treatment of the 

2009 and/or 2010 biomass-based diesel 

standard, and the extent to which RFS1 

RINs should be valid to show 

compliance with RFS2 standards. 

2. Treatment of Biomass-Based Diesel in 

2009 and 2010 

We are proposing to make the RFS2 

program required through EISA effective 

on January 1, 2010. The RFS2 program 

would include an expansion to four 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24957 

34See 73 FR 70643. 35See 72 FR 23935. 

separate standards, changes to the RIN 

system, changes to renewable fuel 

definitions, the introduction of lifecycle 

GHG reduction thresholds, and the 

expansion of obligated parties to 

include producers and importers of 

diesel and nonroad fuel. However, EISA 

requires promulgation of the final RFS2 

regulations within one year of 

enactment and presumes full 

implementation by January 1, 2009. 

Moreover, EISA specifies new volume 

requirements for biomass-based diesel, 

advanced biofuel, and total renewable 

fuel for 2009. As described in Section 

II.A.5, it is not possible to have the full 

RFS2 program implemented by January 

1, 2009. As a result, we must consider 

how to treat these separate volume 

requirements for 2009. 

a. Proposed Shift in Biomass-Based 

Diesel Requirement From 2009 to 2010 

The statutory language in EISA does 

not indicate that the existing RFS1 

regulations cease to apply on January 1, 

2009. Rather, it directs us to ‘‘revise the 

regulations’’ to ensure that the required 

volumes of renewable fuel are contained 

in transportation fuel. As a result, until 

the RFS1 regulations are changed 

through a notice and comment 

rulemaking process, they will remain in 

effect. If the full RFS2 program goes into 

effect on January 1, 2010, then the 

existing RFS1 regulations will continue 

to apply in 2009. 

Under RFS1, we set the applicable 

standard each November for the 

following compliance period using the 

required volume of renewable fuel 

specified in the Clean Air Act, gasoline 

volume projections from EIA, and the 

formula provided in the regulations at 

§ 80.1105(d). Since final RFS2 

regulations will not be promulgated by 

the end of 2008, this RFS1 standardsetting process will apply to the 2009 

compliance period as well. However, 

EISA modifies the Clean Air Act to 

increase the required volume of total 

renewable fuel for 2009 from 6.1 to 11.1 

billion gallons, and thus the applicable 

standard for 2009, published in 

November of 2008,34 reflects this higher 

volume. This will ensure that the total 

renewable fuel requirement under EISA 

for 2009 is implemented. 

While the total renewable fuel volume 

of 11.1 billion gallons will be required 

in 2009, the existing RFS1 regulations 

do not provide a mechanism for 

requiring the 0.5 billion gallons of 

biomass-based diesel or the 0.6 billion 

gallons of advanced biofuel required by 

EISA for 2009. Below we describe our 

proposed approach for biomass-based 

diesel. With regard to advanced biofuel, 

we believe that it is not necessary to 

implement a separate requirement for 

the 0.6 billion gallons. Due to the nested 

nature of the volume requirements, the 

0.5 billion gallon requirement for 

biomass-based diesel would count 

towards meeting the advanced biofuel 

requirement, leaving just 0.1 billion 

gallons that we believe will be supplied 

through imports of sugar-based ethanol 

even without a specific mandate for 

advanced biofuel. 

We believe that the deficit carryover 

provision provides a conceptual 

mechanism for ensuring that the volume 

of biomass-based diesel that is required 

by EISA for 2009 is actually consumed. 

As described in the RFS1 final rule, the 

statute permits obligated parties to carry 

a deficit of any size from one 

compliance period to the next, so long 

as a deficit is not carried over two years 

in a row.35 In theory this would allow 

any and all obligated parties to defer 

compliance with any or all of the 2009 

standards until 2010. Based on the 

precedent set by this statutory 

provision, we propose that the 

compliance demonstration for the 2009 

biomass-based diesel requirement be 

extended to 2010. We believe this 

approach would provide a reasonable 

transition for biomass-based diesel, 

given our inability to issue regulations 

before the beginning of the 2009 

calendar year. Our proposed approach 

would implement the 2009 and 2010 

biomass-based diesel volume 

requirements in a way that ensures that 

these two years worth of biomass-based 

diesel would be used, while providing 

reasonable lead time for obligated 

parties. It would avoid a transition that 

fails to have any requirements related to 

the 2009 biomass-based diesel volume, 

and instead would require the use of the 

2009 volume but would achieve this by 

extending the compliance period by one 

year. We believe this is a reasonable 

exercise of our authority under section 

211(o)(2) to issue regulations that ensure 

that the volumes for 2009 are ultimately 

used, even though we are unable to 

issue final regulations prior to the 2009 

compliance year. In addition, it is a 

practical approach that provides 

obligated parties with appropriate lead 

time. 

To implement our proposed 

approach, the 2009 requirement of 0.5 

billion gallons of biomass-based diesel 

would be combined with the 2010 

requirement of 0.65 billion gallons for a 

total adjusted 2010 requirement of 1.15 

billion gallons of biomass-based diesel. 

The net effect is that obligated parties 

can demonstrate compliance with both 

the 2009 and 2010 biomass-based diesel 

requirements in 2010, consistent with 

what the deficit carryover provision 

would have allowed had we been able 

to implement the full RFS2 program by 

January 1, 2009. 

Furthermore, we propose to allow all 

2009 biodiesel and renewable diesel 

RINs, identifiable through an RR code of 

15 or 17 respectively, to be valid for 

showing compliance with the adjusted 

2010 biomass-based diesel standard of 

1.15 billion gallons. This use of 

previous year RINs for current year 

compliance would be consistent with 

our approach to any other standard for 

any other year and consistent with the 

flexibility available to any obligated 

party that carried a deficit from one year 

to the next. Moreover, it allows an 

obligated party to acquire sufficient 

biodiesel and renewable diesel RINs 

during 2009 to comply with the 0.5 

billion gallons requirement, even 

though their compliance demonstration 

would not occur until the 2010 

compliance period. 

While we recognize that RINs 

generated in 2009 under RFS1 

regulations will differ from those 

generated in 2010 under RFS2 

regulations in terms of the purpose of 

the D code and the other criteria for 

establishing the eligibility of renewable 

fuel, we believe that the use of 2009 

RINs for compliance with the 2010 

adjusted standard is appropriate. It is 

also consistent with CAA section 

211(o)(5), which provides that validly 

generated credits may be used to show 

compliance for 12 months. The program 

transition issue of RINs generated under 

RFS1 but used to meet standards under 

RFS2 is discussed in more detail in 

Section III.G.3 below. 

Rather than reducing the 2009 volume 

requirement for total renewable fuel by 

0.5 billion gallons of biomass-based 

diesel and increasing the 2010 volume 

requirements for advanced biofuel and 

total renewable fuel by the same 

amount, we are proposing that the only 

standard that would be adjusted would 

be that for biomass-based diesel in 2010. 

This approach would minimize the 

changes to the annual RFS volume 

requirements and thus would more 

directly implement the requirements of 

the statute. However, this approach 

would also require that we allow 2009 

biodiesel and renewable diesel RINs to 

be used for compliance purposes for 

both the 2009 total renewable fuel 

standard as well as the 2010 adjusted 

biomass-based diesel standard, but not 

for the 2010 advanced biofuel or total 

renewable fuel standards. We have 

24958 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

identified two possible options for 

accomplishing this. 

i. First Option for Treatment of 2009 

Biodiesel and Renewable Diesel RINs 

In the first option, an obligated party 

would add up the 2009 biodiesel and 

renewable diesel RINs that he used for 

2009 compliance with the RFS1 

standard for renewable fuel, and reduce 

his 2010 biomass-based diesel 

obligation by this amount. Any 

remaining 2010 biomass-based diesel 

obligation would need to be covered 

with either 2009 biodiesel and 

renewable diesel RINs that were not 

used for compliance with the renewable 

fuel standard in 2009, or 2010 biomassbased diesel RINs. This is the option we 

are proposing in today’s notice. 

The primary drawback of our 

proposed option is that 2009 biodiesel 

and renewable diesel RINs used to 

demonstrate compliance with the 2009 

renewable fuel standard could not be 

traded to any other party for use in 

complying with the 2010 biomass-based 

diesel standard. Thus, for instance, if a 

refiner acquired many 2009 biodiesel 

and renewable diesel RINs and used 

them for compliance with the 2009 

renewable fuel standard, and if the 

number of these 2009 RINs was more 

than he needed to comply with his 2010 

biomass-based diesel obligation, he 

could not trade the excess to another 

party. These excess RINs could never be 

applied to the adjusted 2010 biomassbased diesel standard by any party, and 

as a result the actual demand for 

biomass-based diesel could exceed 1.15 

bill gal. We believe that obligated 

parties could avoid this outcome by 

planning ahead to use no more 2009 

biodiesel and renewable diesel RINs for 

2009 compliance with the renewable 

fuel standard than they would need for 

2010 compliance with the adjusted 

biomass-based diesel standard. 

Moreover, this option could provide 

obligated parties with sufficient 

incentive to collect 0.5 billion gallons 

worth of biodiesel and renewable diesel 

RINs in 2009 without significant 

changes to the program’s requirements. 

ii. Second Option for Treatment of 2009 

Biodiesel and Renewable Diesel RINs 

Under the second option, biodiesel 

and renewable diesel RINs generated in 

2009 would be allowed to be used for 

compliance purposes in both 2009 and 

2010. To enable this option, for the 

specific and limited case of biodiesel 

and renewable diesel RINs generated in 

2009, we would modify the regulatory 

prohibition at § 80.1127(a)(3) limiting 

the use of RINs for compliance 

demonstrations to a single compliance 

year to allow 2009 biodiesel and 

renewable diesel RINs to be used for 

compliance purposes in two different 

years. This change would allow all 2009 

biodiesel and renewable diesel RINs to 

be used to meet the adjusted biomassbased diesel standard in 2010 regardless 

of whether they were also used to meet 

the total renewable fuel standard in 

2009. We would also need to lift the 

20% rollover cap that would otherwise 

limit the use of 2009 RINs in 2010, and 

instead allow any number of 2009 

biodiesel and renewable diesel RINs to 

be used to meet the 2010 biomass-based 

diesel standard. 

This option would also require that 

we implement additional RIN tracking 

procedures. Under the current RFS1 

regulations, RINs used for compliance 

demonstrations are removed from the 

RIN market, while under this alternative 

approach biodiesel and renewable 

diesel RINs could continue to be valid 

for compliance purposes vis a vis the 

adjusted 2010 biomass-based diesel 

standard even if they were already used 

for compliance with the renewable fuel 

standard in 2009. The regulations would 

need to be changed to allow this, and 

both EPA’s and industry’s IT systems 

would need to be modified to allow for 

this temporary change. 

Due to the additional complexities 

associated with this option, we are not 

proposing it. Nevertheless, we request 

comment on it, as it would more 

explicitly reflect two separate 

obligations for calendar year 2009: An 

RFS1 obligation for total renewable fuel, 

and an obligation for biomass-based 

diesel that starts during 2009 with 

compliance required by the end of 2010 

for a volume that covers both 2009 and 

2010. We also request comment on 

whether under this option we should 

allow 2009 biodiesel and renewable 

diesel RINs to continue to be bought and 

sold after 2009 if they are used to 

demonstrate compliance with the 2009 

total renewable fuel standard. 

b. Proposed Treatment of Deficit 

Carryovers and Valid RIN Life For 

Adjusted 2010 Biomass-Based Diesel 

Requirement 

Although our proposed transition 

approach is conceptually similar to the 

statutory deficit carryover provision, the 

regulatory requirements would not 

explicitly treat the movement of the 0.5 

billion gallons biomass-based diesel 

requirement from 2009 to 2010 as a 

deficit carryover. In the absence of any 

modifications to the deficit carryover 

provisions, then, an obligated party that 

did not fully comply with the 2010 

biomass-based diesel requirement of 

1.15 billion gallons could carry a deficit 

of any amount into 2011. 

If we had been able to implement the 

2009 biomass-based diesel volume 

requirement of 0.5 billion gallons in 

calendar year 2009, the 2010 biomassbased diesel standard would have been 

based on 0.65 billion gallons. In this 

case, the maximum volume of biomassbased diesel that could have been 

carried into 2011 as a deficit would 

have been 0.65 billion gallons. In the 

context of our proposed approach to the 

treatment of biomass-based diesel in 

2009 and 2010, we believe that it would 

be inappropriate to allow the full 1.15 

billion gallons to be carried into 2011 as 

a deficit. Therefore, we are proposing 

that obligated parties be prohibited from 

carrying over a deficit into 2011 larger 

than 0.65 bill gal. In practice, this would 

mean that deficit carryovers from 2010 

into 2011 for biomass-based diesel 

could not exceed 57% of an obligated 

party’s 2010 RVO. 

Similarly, the combination of the 0.5 

billion gallons biomass-based diesel 

requirement from 2009 with the 2010 

volume raises the question of whether 

2008 biodiesel or renewable diesel RINs 

could be used for compliance in 2010 

with the adjusted biomass-based diesel 

standard. Without a change to the 

regulations, this practice would not be 

allowed because RINs are only valid for 

compliances purposes for the year 

generated or the year after. However, if 

we had been able to implement the full 

RFS2 program for the 2009 compliance 

year, 2008 biodiesel and renewable 

diesel RINs would be valid for 

compliance with the 0.5 billion gallons 

biomass-based diesel requirement. 

Therefore, we are proposing to modify 

the regulations to allow excess 2008 

biodiesel and renewable diesel RINs to 

be used for compliance purposes in 

2009 or 2010. We request comment on 

this proposal. 

We also propose that the 20% rollover 

cap would continue to apply in all years 

as described in more detail in Section 

IV.D. However, we are proposing an 

additional constraint in the application 

of this cap to the biomass-based diesel 

obligation in the 2010 compliance year. 

If the 2009 biomass-based diesel volume 

requirement of 0.5 billion gallons could 

have been required in 2009, the use of 

excess 2008 biodiesel and renewable 

diesel RINs would have been limited to 

20% of the 2009 requirement, or a 

maximum of 0.1 billion gallons. Since 

we are proposing to require that the 

2009 and 2010 biomass-based diesel 

requirements be combined for a total of 

1.15 billion gallons, we propose that the 

maximum allowable portion that could 

be derived from 2008 biomass-based 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24959 

diesel RINs would be 0.1 billion gallons. 

This would represent 8.7% of the 2010 

obligation (0.1⁄1.15). In addition to this 

limit on the use of 2008 RINs for 2010 

compliance that is unique to this option, 

the 20% rollover cap would continue to 

apply to the use of all previous-year 

RINs used for compliance purposes in 

2010. Thus, the total number of all 2008 

and 2009 RINs that could be used to 

meet the 2010 biomass-based diesel 

obligation would continue to be capped 

at 20%. We request comment on this 

approach. 

Finally, we are proposing to allow 

2009 RINs that are retired because they 

are ultimately used for nonroad or home 

heating oil purposes to be valid for 

compliance with the 2010 RFS standard. 

Currently, under RFS1, RINs associated 

with renewable fuel that is not 

ultimately used as motor vehicle fuel 

must be retired. In contrast, under EISA, 

renewable fuel used for nonroad 

purposes, except for use in industrial 

boilers or ocean-going vessels, is 

considered transportation fuel, and is 

eligible for the RFS program. We are 

proposing that 2009 RINs generated for 

renewable fuel that is ultimately used 

for nonroad or home heating oil 

purposes continue to be retired by the 

appropriate party pursuant to 

80.1129(e). However, we are proposing 

that those retired 2009 nonroad or home 

heating oil RINs be eligible for 

reinstatement by the retiring party in 

2010. These reinstated RINs may be 

used by that party to demonstrate 

compliance with a 2010 RVO, or for sale 

to other parties who would then use the 

RINs for compliance purposes. While 

we anticipate that this proposed 

provision would be utilized largely for 

biodiesel RINs that were retired by 

parties that sold them for use as 

nonroad fuel or home heating oil, we 

propose that the provision apply to all 

RINs. We request comment on this 

proposed approach. 

c. Alternative Approach to Treatment of 

Biomass-Based Diesel in 2009 and 2010 

Under our proposed approach, the 0.5 

billion gallon requirement for biomassbased diesel in 2009 would be added to 

the 0.65 billion gallon requirement for 

2010, and the total volume of 1.15 

billion gallons would be used as the 

basis of a single adjusted standard 

applicable to obligated parties in 2010. 

The compliance demonstration for this 

single standard would need to be made 

by February 28, 2011. As an alternative, 

we could establish two separate 

biomass-based diesel standards for 

which compliance must be 

demonstrated by February 28, 2011. One 

of these standards would be based on 

0.65 billion gallons and would represent 

the applicable biomass-based diesel 

standard for 2010. The other standard 

would be based on 0.5 billion gallons 

and would represent the applicable 

biomass-based diesel standard for 2009. 

In essence, the standard based on 0.5 

billion gallons would be for the 2009 

calendar year even though we would 

extend its compliance demonstration 

until February 28, 2011. 

In this alternative, only excess 2008 or 

2009 biodiesel and renewable diesel 

RINs could be used to comply with the 

standard based on 0.5 billion gallons. 

Excess 2009 biodiesel or renewable 

diesel RINs and 2010 biomass-based 

diesel RINs could be used to comply 

with the standard based on 0.65 billion 

gallons. The 20% rollover cap would 

apply to both standards. As a result, this 

alternative approach would effectively 

implement the 2009 biomass-based 

diesel standard in calendar year 2009, 

and thus it may come closer to the 

statute’s requirements than our 

proposed approach. Moreover, the 

existing provisions for the valid life of 

RINs and deficit carryover would not 

need modification as they would under 

our proposed approach. 

However, this alternative would 

arguably provide less than appropriate 

lead time for meeting the 0.5 billion 

gallon obligation, as it would require 

obligated parties to begin acquiring 

sufficient 2008 and 2009 biodiesel and 

renewable diesel RINs starting in 

January of 2009 even though our final 

rulemaking is not expected to be issued 

until the fall of 2009. There are two 

reasons that this lead time might 

nevertheless be considered appropriate. 

First, obligated parties could wait until 

the final rule is published to begin 

acquiring 2008 and 2009 biodiesel and 

renewable diesel RINs. Moreover, they 

would not need to demonstrate 

compliance with the 0.5 billion gallons 

standard until February 28, 2011, 

providing ample time to locate and 

acquire sufficient RINs. Second, the 

deficit carryover provisions would 

allow obligated parties to treat the 

separate 0.5 and 0.65 billion gallon 

requirements as a single requirement 

that must be met in total by February 28, 

2011. In this sense, this alternative is 

similar to our proposed approach. We 

request comment on this alternative 

approach. 

d. Treatment of Biomass-Based Diesel 

Under an RFS2 Effective Date Other 

Than January 1, 2010 

The above discussion assumes that 

the RFS2 program is effective on 

January 1, 2010. If the program effective 

date is delayed, similar issues arise 

regarding whether EISA volume 

mandates for fuel categories with no 

mandates under RFS1 are lost, or should 

be recaptured through a delayed 

compliance demonstration in the first 

year of the RFS2 program. For a delay 

beyond January 1, 2010, the issues relate 

to cellulosic biofuel and advanced 

biofuel in addition to biomass-based 

diesel. 

For instance, our proposed approach 

to biomass-based diesel effectively 

makes the one-year deficit carryover a 

necessary element of compliance for 

2010, and maintains the two-year valid 

life of RINs. However, if the effective 

date of RFS2 were delayed to January 1, 

2011, we could not take the same 

approach. By requiring compliance 

demonstrations to be made in 2011 for 

the required biomass-based diesel 

volumes mandated for 2009, 2010, and 

2011, we would be effectively requiring 

a 2-year deficit carryover and a threeyear valid life of RINs, contrary to the 

statutory limitations. As an alternative, 

one possible approach would be to only 

sum the required biomass-based diesel 

volumes for 2010 and 2011 and require 

compliance demonstrations at the end 

of 2011. 

If the RFS2 program became effective 

in mid-2010, we would also need to 

determine the appropriate level of the 

biomass-based diesel standard, and 

whether it would apply to gasoline and 

diesel volumes produced only after the 

RFS2 effective date, or all gasoline and 

diesel volumes produced in 2010. 

EPA invites comment on whether and 

how it should recapture these volume 

mandates under different start-date 

scenarios. 

F. Fuels That Are Subject to the 

Standards 

Under RFS1, producers and importers 

of gasoline are obligated parties subject 

to the standards. Any party that 

produces or imports only diesel fuel is 

not subject to the standards. EISA 

changes this provision by expanding the 

RFS program in general to include 

transportation fuel. As discussed above, 

however, section 211(o)(3) continues to 

require EPA to determine which 

refiners, blenders, and importers are 

treated as subject to the standard. As 

described further in Section III.G below, 

we are proposing that the sum of all 

highway and nonroad gasoline and 

diesel fuel produced or imported within 

a calendar year be the basis on which 

the RVOs are calculated. This section 

provides our proposed definition of 

gasoline and diesel for the purposes of 

the RFS program. 

24960 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

36EPA’s diesel fuel regulations use the term 

‘‘nonroad’’ to designate one large category of landbased off-highway engines and vehicles, 

recognizing that locomotive and marine engines 

and vessels are also nonroad engines and vehicles 

under EPAct’s definition of nonroad. Except where 

noted, the discussion of nonroad in reference to 

transportation fuel includes the entire category 

covered by EPAct’s definition of nonroad. 

37See 40 CFR 80.598(a) for the kinds of fuel types 

used by refiners or importers in designating their 

diesel fuel. 

1. Gasoline 

As with the RFS1 program, the 

volume of gasoline used in calculating 

the RVO under RFS2 would continue to 

include all finished gasoline 

(reformulated gasoline (RFG) and 

conventional gasoline (CG)) produced or 

imported for use in the contiguous 

United States or Hawaii, as well as all 

unfinished gasoline that becomes 

finished gasoline upon the addition of 

oxygenate blended downstream from 

the refinery or importer. This would 

include both unfinished reformulated 

gasoline, called ‘‘reformulated gasoline 

blendstock for oxygenate blending,’’ or 

‘‘RBOB,’’ and unfinished conventional 

gasoline designed for downstream 

oxygenate blending (e.g., sub-octane 

conventional gasoline), called ‘‘CBOB.’’ 

The volume of any other unfinished 

gasoline or blendstock, such as butane 

or naphtha produced in a refinery, 

would not be included in the obligated 

volume, except where the blendstock is 

combined with other blendstock or 

gasoline to produce finished gasoline, 

RBOB, or CBOB. Where a blendstock is 

blended with other blendstock to 

produce finished gasoline, RBOB, or 

CBOB, the total volume of the gasoline 

blend would be included in the volume 

used to determine the blender’s 

renewable fuels obligation. Where a 

blendstock is added to finished 

gasoline, only the volume of the 

blendstock would be included, since the 

finished gasoline would have been 

included in the compliance 

determinations of the refiner or importer 

of the gasoline. For purposes of this 

preamble, the various gasoline products 

described above that we are proposing 

to include in a party’s obligated volume 

would collectively be called ‘‘gasoline.’’ 

Also consistent with the RFS1 

program, we propose to continue to 

exclude any volume of renewable fuel 

contained in gasoline from the volume 

of gasoline used to determine the 

renewable fuels obligations. This 

exclusion would apply to any renewable 

fuels that are blended into gasoline at a 

refinery, contained in imported 

gasoline, or added at a downstream 

location. Thus, for example, any ethanol 

added to RBOB or CBOB at a refinery’s 

rack or terminal downstream from the 

refinery or importer would be excluded 

from the volume of gasoline used by the 

refiner or importer to determine the 

obligation. This is consistent with how 

the standard itself is calculated—EPA 

determines the applicable percentage by 

comparing the overall projected volume 

of gasoline used to the overall 

renewable fuel volume that is specified 

in EPAct, and EPA excludes ethanol and 

other renewable fuels that blended into 

the gasoline in determining the overall 

projected volume of gasoline. When an 

obligated party determines their RVO by 

applying the applicable percentage to 

the amount of gasoline they produce or 

import, it is consistent to also exclude 

ethanol and other renewable fuel blends 

from the calculation of the volume of 

gasoline produced. 

As with the RFS1 program, we are 

proposing that Gasoline Treated as 

Blendstock (GTAB) would continue to 

be treated as a blendstock under the 

RFS2 program, and thus would not 

count towards a party’s renewable fuel 

obligation. Where the GTAB is blended 

with other blendstock (other than 

renewable fuel) to produce gasoline, the 

total volume of the gasoline blend, 

including the GTAB, would be included 

in the volume of gasoline used to 

determine the renewable fuel obligation. 

Where GTAB is blended with renewable 

fuel to produce gasoline, only the GTAB 

volume would be included in the 

volume of gasoline used to determine 

the renewable fuel obligation. Where the 

GTAB is blended with finished gasoline, 

only the GTAB volume would be 

included in the volume of gasoline used 

to determine the renewable fuel 

obligation. 

2. Diesel 

As discussed above in Section II.A.4, 

EISA expanded the RFS program to 

include transportation fuels other than 

gasoline, and we are proposing that both 

highway and nonroad diesel be used in 

calculating a party’s RVO. We are 

proposing that any party that produces 

or imports petroleum-based diesel fuel 

that is designated as motor vehicle, 

nonroad, locomotive, and marine diesel 

fuel (MVNRLM) (or any subcategory of 

MVNRLM) would be required to include 

the volume of that diesel fuel in the 

determination of its RVO under the 

RFS2 rule. We are proposing that diesel 

fuel would include any distillate fuel 

that meets the definition of MVNRLM 

diesel fuel as it has already been defined 

in the regulations at § 80.2(qqq), 

including any subcategories such as MV 

(motor vehicle diesel produced for use 

in highway diesel engines and vehicles), 

NRLM (diesel produced for use in 

nonroad, locomotive, and marine diesel 

engines and equipment/vessels), NR 

(diesel produced for use in nonroad 

engines and equipment), and LM (diesel 

produced for use in locomotives and 

marine diesel engines and vessels).36

We are proposing that transportation 

fuels meeting the definition of 

MVNRLM would be used to calculate 

the RVOs, and refiners, blenders, or 

importers of MVNRLM would be treated 

as obligated parties. As such, diesel fuel 

that is designated as heating oil, jet fuel, 

or any designation other than MVNRLM 

or a subcategory of MVNRLM, would 

not be subject to the applicable 

percentage standard and would not be 

used to calculate the RVOs.37

We are also requesting comment on 

the idea that any diesel fuel not meeting 

these requirements, such as distillate or 

residual fuel intended solely for use in 

ocean-going vessels, would not be used 

to calculate the RVOs. As discussed 

above in Section II.A.4, EISA specifies 

that ‘‘transportation fuels’’ do not 

include fuels for use in ocean-going 

vessels. We are interpreting the term 

‘‘ocean-going vessel’’ to mean those 

vessels that are powered by Category 3 

(C3) marine engines and that use 

residual fuel or operate internationally; 

we request comment on this 

interpretation. As such, we are 

requesting comment on the concept that 

fuel intended solely for use in oceangoing vessels, or that an obligated party 

can verify as having been used in an 

ocean-going vessel, would be excluded 

from the renewable fuel standards. 

Further, we are also requesting 

comment on whether fuel used on such 

vessels with C2 engines should also be 

excluded from the renewable fuel 

standards, and how such an exemption 

should be phrased. 

3. Other Transportation Fuels 

As discussed further in Section III.J.3, 

below, we propose that transportation 

fuels other than gasoline or MVNRLM 

diesel fuel (natural gas, propane, and 

electricity) would not be used to 

calculate the RVOs of any obligated 

party. We believe this is a reasonable 

way to implement the obligations of 

211(o)(3) because the volumes are small 

and the producers cannot readily 

differentiate the small transport portion 

from the large non-transport portion (in 

fact, the producer may have no 

knowledge of its use in transport); we 

will reconsider this approach if and 

when these volumes grow. At the same 

time, it is clear that other fuels can meet 

the definition of ‘‘transportation fuel,’’ 

and we are proposing that under certain 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24961 

38As discussed above, the diesel fuel that is used 

to calculate the RVO is any diesel designated as 

MVNRLM or a subcategory of MVNRLM. 

circumstances, producers or generators 

of such other transportation fuels may 

generate RINs as a producer or importer 

of a renewable fuel. See Section III.B.1.a 

for further discussion of other RINgenerating fuels. 

G. Renewable Volume Obligations 

(RVOs) 

Under the current RFS program, each 

obligated party must determine its RVO 

based on the applicable percentage 

standard and its annual gasoline 

volume. The RVO represents the volume 

of renewable fuel that the obligated 

party must ensure is used in the U.S. in 

a given calendar year. Obligated parties 

must meet their RVO through the 

accumulation of RINs which represent 

the amount of renewable fuel used as 

motor vehicle fuel that is sold or 

introduced into commerce within the 

U.S. Each gallon-RIN would count as 

one gallon of renewable fuel for 

compliance purposes. 

We propose to maintain this approach 

to compliance under the RFS2 program. 

One primary difference between the 

current and new RFS programs in terms 

of demonstrating compliance would be 

that each obligated party would now 

have four RVOs instead of one (through 

2012) or two (starting in 2013) under the 

RFS1 program. Also, as discussed 

above, RVOs would be calculated based 

on production or importation of both 

gasoline and diesel fuels, rather than 

gasoline alone. 

By acquiring RINs and applying them 

to their RVOs, obligated parties are 

effectively causing the renewable fuel 

represented by the RINs to be consumed 

as transportation fuel in highway or 

nonroad vehicles or engines. Obligated 

parties would not be required to 

physically blend the renewable fuel into 

gasoline or diesel fuel themselves. The 

accumulation of RINs would continue to 

be the means through which each 

obligated party shows compliance with 

its RVOs and thus with the renewable 

fuel standards. 

If an obligated party acquires more 

RINs than it needs to meet its RVOs, 

then in general it could retain the excess 

RINs for use in complying with its RVOs 

in the following year or transfer the 

excess RINs to another party. If, 

alternatively, an obligated party has not 

acquired sufficient RINs to meet its 

RVOs, then under certain conditions it 

could carry a deficit into the next year. 

This section describes our proposed 

approach to the calculation of RVOs 

under RFS2 and the RINs that would be 

valid for demonstrating compliance 

with those RVOs. This includes a 

description of the special treatment that 

must be applied to 2009 RINs used for 

compliance purposes in 2010, since 

RINs generated in 2009 under RFS1 

would not be exactly the same as those 

generated in 2010 under RFS2. We also 

describe an alternative approach to the 

identification of obligated parties that 

would place the obligations under RFS2 

on only finished gasoline and diesel 

rather than on certain blendstocks and 

unfinished fuels as well. The 

implication of this would be that the 

final blender of the gasoline or diesel 

would be the obligated parties rather 

than producers of blendstocks and 

unfinished fuels. 

1. Determination of RVOs 

Corresponding to the Four Standards 

In order for an obligated party to 

demonstrate compliance, the percentage 

standards described in Section III.E.1 

which are applicable to all obligated 

parties must be converted into the 

volumes of renewable fuel each 

obligated party is required to satisfy. 

These volumes of renewable fuel are the 

volumes for which the obligated party is 

responsible under the RFS program, and 

are referred to here as its RVO. Under 

RFS2, each obligated party would need 

to acquire sufficient RINs each year to 

meet each of the four RVOs 

corresponding to the four renewable 

fuel standards. 

The calculation of the RVOs under 

RFS2 would follow the same format as 

the existing formulas in the regulations 

at § 80.1107(a), with one modification. 

The standards for a particular 

compliance year would be multiplied by 

the sum of the gasoline and diesel 

volume produced or imported by an 

obligated party in that year rather than 

only the gasoline volume as under the 

current program.38 To the degree that an 

obligated party did not demonstrate full 

compliance with its RVOs for the 

previous year, the shortfall would be 

included as a deficit carryover in the 

calculation. CAA section 211(o)(5) only 

permits a deficit carryover from one 

year to the next if the obligated party 

achieves full compliance with its RVO 

including the deficit carryover in the 

second year. Thus deficit carryovers 

could not occur two years in succession 

for any of the four standards. They 

could, however, occur as frequently as 

every other year for a given obligated 

party. 

Note that a party that produces only 

diesel fuel would have an obligation for 

all four standards even though he would 

not have the opportunity to blend 

ethanol into his own gasoline. Likewise, 

a party that produces only gasoline will 

have an obligation for all four standards 

even though he would not have an 

opportunity to blend biomass-based 

diesel into his own diesel fuel. 

Although these circumstances might 

imply that the four standards should be 

further subdivided into gasoline-specific 

and diesel-specific standards, we do not 

believe that this would be appropriate 

as described in Section III.E.1. Instead, 

since the obligations are met through 

the use of RINs, compliance with the 

standards does not require an obligated 

party to blend renewable fuel into their 

own or anyone else’s gasoline or diesel 

fuel. 

2. RINs Eligible To Meet Each RVO 

Under RFS1, all RINs had the same 

compliance value and thus it did not 

matter what the RR or D code was for 

a given RIN when using that RIN to 

meet the total renewable fuel standard. 

In contrast, under RFS2 only RINs with 

specified D codes could be used to meet 

each of the four standards. 

As described in Section II.A.1, the 

volume requirements in EISA are 

generally nested within one another, so 

that the advanced biofuel requirement 

includes fuel that meets either the 

cellulosic biofuel or the biomass-based 

diesel requirements, and the total 

renewable fuel requirement includes 

fuel that meets the advanced biofuel 

requirement. As a result, the RINs that 

can be used to meet the four standards 

are likewise nested. Using the proposed 

D codes defined in Table III.A–1, the 

RINs that could be used to meet each of 

the four standards are shown in Table 

III.G.2–1. 

TABLE III.G.2–1—RINS THAT CAN BE USED TO MEET EACH STANDARD

Standard Obligation Allowable D codes 

Cellulosic biofuel .............................................................................................................................. RVOCB ....................... 1. 

24962 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

39Note that we are proposing an exception to this 

general prohibition for the specific and limited case 

of excess 2008 and 2009 biodiesel and renewable 

diesel RINs used to demonstrate compliance with 

both the 2009 total renewable fuel standard and the 

2010 biomass-based diesel standard. See Section 

III.E.2.a. 

TABLE III.G.2–1—RINS THAT CAN BE USED TO MEET EACH STANDARD—Continued 

Standard Obligation Allowable D codes 

Biomass-based diesel ...................................................................................................................... RVOBBD ..................... 2. 

Advanced biofuel ............................................................................................................................. RVOAB ....................... 1, 2, and 3. 

Renewable fuel ................................................................................................................................ RVORF ....................... 1, 2, 3, and 4. 

The nested nature of the four 

standards also means that we must 

allow the same RIN to be used to meet 

more than one standard in the same 

year. Thus, for instance, a RIN with a D 

code of 1 could be used to meet three 

of the four standards, while a RIN with 

a D code of 3 could be used to meet both 

the advanced biofuel and total 

renewable fuel standards. However, we 

propose continuing to prohibit the use 

of a single RIN for compliance purposes 

in more than one year or by more than 

one party.39

3. Treatment of RFS1 RINs Under RFS2 

As described in Section II.A, we are 

proposing a number of changes to the 

RFS program as a result of the 

requirements in EISA. These changes 

would go into effect on January 1, 2010 

and, among other things, would affect 

the conditions under which RINs are 

generated and their applicability to each 

of the four standards. As a result, RINs 

generated in 2010 under RFS2 will not 

be exactly the same as RINs generated 

in 2009 under RFS1. Given the valid 

RIN life that allows a RIN to be used in 

the year generated or the year after, we 

must address circumstances in which 

excess 2009 RINs are used for 

compliance purposes in 2010. We must 

also address deficit carryovers from 

2009 to 2010, since the total renewable 

fuel standards in these two years will be 

defined differently. 

a. Use of 2009 RINs in 2010 

In 2009, the RFS1 regulations will 

continue to apply and thus producers 

will not be required to demonstrate that 

their renewable fuel is made from 

renewable biomass as defined by EISA, 

nor that their combination of fuel type, 

feedstock, and process meets the GHG 

thresholds specified in EISA. Moreover, 

there is no practical way to determine 

after the fact if RINs generated in 2009 

meet any of these criteria. However, we 

believe that the vast majority of RINs 

generated in 2009 would in fact meet 

the RFS2 requirements. First, while 

ethanol made from corn must meet a 

20% GHG threshold under RFS2 if 

produced by a facility that commenced 

construction after December 19, 2007, 

facilities that were already built or had 

commenced construction as of 

December 19, 2007 are exempt from this 

requirement. Essentially all ethanol 

produced in 2009 will meet the 

prerequisites for this exemption. 

Second, it is unlikely that renewable 

fuels produced in 2009 will have been 

made from feedstocks grown on 

agricultural land that had not been 

cleared or cultivated prior to December 

19, 2007. In the intervening time period, 

it is much more likely that the 

additional feedstocks needed for 

renewable fuel production would come 

from existing cropland or cropland that 

has lain fallow for some time. Finally, 

the text of section 211(o)(5) states that 

a ‘‘credit generated under this paragraph 

shall be valid to show compliance for 

the 12 months as of the date of 

generation,’’ and EISA did not change 

this provision and did not specify any 

particular transition protocol to follow. 

A straightforward interpretation of this 

provision is to allow 2009 RINs to be 

valid to show compliance for 2010 

obligations. 

Since there will be separate standards 

for cellulosic biofuel and biomass-based 

diesel in 2010, RINs generated in 2009 

that could be used to meet either of 

these two 2010 standards should meet 

the GHG thresholds of 60% and 50%, 

respectively. While we will not have a 

mechanism in place to determine if 

these thresholds have been met for RINs 

generated in 2009, and there are 

indications from our assessment of 

lifecycle GHG performance that at least 

some renewable fuels produced in 2009 

would not meet these thresholds, 

nevertheless any shortfall in GHG 

performance for this one transition year 

is unlikely to have a significant impact 

on long-term GHG benefits of the 

program. Based on our belief that it is 

critical to the smooth operation of the 

program that excess 2009 RINs be 

allowed to be used for compliance 

purposes in 2010, we are proposing that 

RINs generated in 2009 to represent 

cellulosic biomass ethanol whose GHG 

performance has not been verified 

would still be valid for use for 2010 

compliance purposes for the cellulosic 

biofuel standard. Likewise, we are 

proposing that RINs generated in 2009 

to represent biodiesel and renewable 

diesel whose GHG performance has not 

been verified would still be valid for use 

for 2010 compliance purposes for the 

biomass-based diesel standard. We 

request comment on this approach. 

We propose to use information 

contained in the RR and D codes of 

RFS1 RINs to determine how those RINs 

should be treated under RFS2. The RR 

code is used to identify the Equivalence 

Value of each renewable fuel, and under 

RFS1 these Equivalence Values are 

unique to specific types of renewable 

fuel. For instance, biodiesel (mono alkyl 

ester) has an Equivalence Value of 1.5, 

and non-ester renewable diesel has an 

Equivalence Value of 1.7, and both of 

these fuels may be valid for meeting the 

biomass-based diesel standard under 

RFS2. Likewise, RINs generated for 

cellulosic biomass ethanol in 2009 must 

be identified with a D code of 1, and 

these fuels may be valid for meeting the 

cellulosic biofuel standard under RFS2. 

Our proposed treatment of 2009 RINs in 

2010 is shown in Table III.G.3.a–1. 

TABLE III.G.3.a–1—PROPOSED TREATMENT OF EXCESS 2009 RINS IN

2010 

Excess 2009 RINs Treatment in 2010 

RFS1 RINs with RR 

code of 15 or 17.

Equivalent to RFS2 

RINs with D code 

of 2. 

RFS1 RINs with D 

code of 1.

Equivalent to RFS2 

RINs with D code 

of 1. 

All other RFS1 RINs .. Equivalent to RFS2 

RINs with D code 

of 4. 

Although we have discussed the issue 

of RFS1 RINs being used for RFS2 

purposes in the context of our proposal 

that the RFS2 program be effective on 

January 1, 2010, we would expect a 

similar treatment of RFS1 RINs for RFS2 

compliance purposes if the RFS2 

effective date is delayed. In that case 

RFS1 RINs generated in 2010 would be 

available to show compliance for both 

the 2010 and 2011 compliance years, in 

a manner similar to that described 

above. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24963 

b. Deficit Carryovers From the RFS1 

Program to RFS2 

If the RFS2 program goes into effect 

on January 1, 2010, the calculation of 

RVOs in 2009 under the existing 

regulations will be somewhat different 

than the calculation of RVOs in 2010 

under RFS2. In particular, 2009 RVOs 

will be based upon gasoline production 

only, while 2010 RVOs would be based 

on volumes of gasoline and diesel. As a 

result, 2010 compliance demonstrations 

that include a deficit carried over from 

2009 will combine obligations 

calculated on two different bases. 

We do not believe that deficits carried 

over from 2009 to 2010 would 

undermine the goals of the program in 

requiring specific volumes of renewable 

fuel to be used each year. Although 

RVOs in 2009 and 2010 would be 

calculated differently, obligated parties 

must acquire sufficient RINs in 2010 to 

cover any deficit carried over from 2009 

in addition to that portion of their 2010 

obligation which is based on their 2010 

gasoline and diesel production. As a 

result, the 2009 nationwide volume 

requirement of 11.1 billion gallons of 

renewable fuel will be consumed over 

the two year period concluding at the 

end of 2010. Thus, we are not proposing 

special treatment for deficits carried 

over from 2009 to 2010. 

We propose that a deficit carried over 

from 2009 to 2010 would only affect a 

party’s total renewable fuel obligation in 

2010 (RVORF,i as discussed in Section 

III.G.1), as the 2009 obligation is for 

total renewable fuel use, not a 

subcategory. The RVOs for cellulosic 

biofuel, biomass-based diesel, or 

advanced biofuel would not be affected, 

as they do not have parallel obligations 

in 2009 under RFS1. 

If the RFS2 start date is delayed to be 

later than January 1, 2010, we expect 

that the same principles described 

above would apply for any deficit 

calculated under the RFS1 program and 

carried forward to RFS2. 

4. Alternative Approach to Designation 

of Obligated Parties 

Under RFS1, obligated parties who 

are subject to the standard are those that 

produce or import finished gasoline 

(RFG and conventional) or unfinished 

gasoline that becomes finished gasoline 

upon the addition of an oxygenate 

blended downstream from the refinery 

or importer. Unfinished gasoline 

includes reformulated gasoline 

blendstock for oxygenate blending 

(RBOB), and conventional gasoline 

blendstock designed for downstream 

oxygenate blending (CBOB) which is 

generally sub-octane conventional 

gasoline. The volume of any other 

unfinished gasoline or blendstock, such 

as butane, is not included in the volume 

used to determine the RVO, except 

where the blendstock is combined with 

other blendstock or finished gasoline to 

produce finished gasoline, RBOB, or 

CBOB. Thus, parties downstream of a 

refinery or importer are only obligated 

parties to the degree that they use nonrenewable blendstocks to make finished 

gasoline, RBOB, or CBOB. 

The approach we took for RFS1 was 

based on our expectation at that time 

that there would be an excess of RINs 

at low cost, and our belief that the 

ability of RINs to be traded freely 

between any parties once separated 

from renewable fuel would provide 

ample opportunity for parties who were 

in need of RINs to acquire them from 

parties who had excess. We also pointed 

out that the designation of ethanol 

blenders as obligated parties would 

have greatly expanded the number of 

regulated parties and increased the 

complexity of the RFS program beyond 

that which was necessary to carry out 

the renewable fuels mandate under CAA 

section 211(o). 

Following the new requirements 

under EISA, the required volumes of 

renewable fuel will be increasing 

significantly above the levels required 

under RFS1. These higher volumes are 

already resulting in changes in the 

demand for RINs and operation of the 

RIN market. First, obligated parties who 

have excess RINs are increasingly opting 

to retain rather than sell them to ensure 

they have a sufficient number for the 

next year’s compliance. Second, since 

all gasoline is expected to contain 

ethanol by 2013, few blenders would be 

able to avoid taking ownership of RINs 

by that time under the existing 

definition of obligated party. As a result, 

by 2013 essentially every blender would 

be a regulated party who is subject to 

recordkeeping and reporting 

requirements, and thus the additional 

burden of demonstrating compliance 

with the standard could be small. Third, 

major integrated refiners who operate 

gasoline marketing operations have 

direct access to RINs for ethanol 

blended into their gasoline, while 

refiners whose operations are focused 

primarily on producing refined products 

do not have such direct access to RINs. 

The result is that in some cases there are 

significant disparities between obligated 

parties in terms of opportunities to 

acquire RINs. If those that have excess 

RINs are reluctant to sell them, those 

who are seeking RINs may be forced to 

market a disproportionate share of E85 

in order to gain access to the RINs they 

need for compliance. If obligated parties 

seeking RINs cannot acquire a sufficient 

number, they can only carry a deficit 

into the following year, after which they 

would be in noncompliance if they 

could not acquire sufficient RINs. The 

result might be a much higher price for 

RINs (and fuel) in the marketplace than 

would be expected under a more liquid 

market. 

Given the change in circumstances 

brought about through EISA, it may be 

appropriate to consider a change in the 

way that obligated parties are defined to 

more evenly align a party’s access to 

RINs with that party’s obligations under 

the RFS2 program. The most 

straightforward approach would be to 

eliminate RBOB and CBOB from the list 

of fuels that are subject to the standard, 

such that a party’s RVO would be based 

only on the non-renewable volume of 

finished gasoline or diesel that he 

produces or imports. Parties that blend 

ethanol into RBOB and CBOB to make 

finished gasoline would thus be 

obligated parties, and their RVOs would 

be based upon the volume of RBOB and 

CBOB prior to ethanol blending. 

Traditional refiners that convert crude 

oil into transportation fuels would only 

have an RVO to the degree that they 

produced finished gasoline or diesel, 

with all RBOB and CBOB sold to 

another party being excluded from the 

calculation of their RVO. 

Since essentially all gasoline is 

expected to be E10 within the next few 

years (see discussion in Section V.D.2 

below), this approach would effectively 

shift the obligation for all gasoline from 

refiners and importers to ethanol 

blenders (who in many cases are still 

the refiners). However, this approach by 

itself would maintain the obligation for 

diesel on refiners and importers. Thus, 

a variation of this approach would be to 

move the obligations for all gasoline and 

diesel downstream to parties who 

supply finished transportation fuels to 

retail outlets or to wholesale purchaserconsumer facilities. This variation 

would have the additional effect of more 

closely aligning obligations and access 

to RINs for parties that blend biodiesel 

and renewable diesel into petroleumbased diesel. 

We are not proposing to eliminate 

RBOB and CBOB from the list of fuels 

that are subject to the standard in 

today’s notice since it would result in a 

significant change in the number of 

obligated parties and the movement of 

RINs. Many parties that are not 

obligated under the current RFS 

program would become obligated, and 

would be forced to implement new 

systems for determining and reporting 

compliance. Nevertheless, it would have 

certain advantages. Currently, blenders 

24964 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

40EISA, Title II, Subtitle A–Renewable Fuel 

Standard, Section 201. 

that are not obligated parties are 

profiting from the sale of RINs they 

acquire through splash blending of 

ethanol. By eliminating RBOB and 

CBOB from the list of obligated fuels, 

these blenders would become directly 

responsible for ensuring that the volume 

requirements of the RFS program are 

met, and the cost of meeting the 

standard would be more evenly 

distributed among parties that blend 

renewable fuel into gasoline. With 

obligations placed more closely to the 

points in the distribution system where 

RINs are made available, the overall 

market prices for RINs may be lowered 

and consequently the cost of the 

program to consumers may be reduced. 

While eliminating the categories of 

RBOB and CBOB from the list of 

obligated fuels would result in a 

significant change in the distribution of 

obligations among transportation fuel 

producers, it could help to ensure that 

the RIN market functions as we 

originally intended. As a result, RINs 

would more directly be made available 

to the parties that need them for 

compliance. This is similar to the goal 

of the direct transfer approach to RIN 

distribution as described in the 

proposed rulemaking for the RFS1 

program and presented again in Section 

III.H.4 below. We request comment on 

the degree to which access to RINs is a 

concern among current obligated 

parties. Since either the elimination of 

RBOB and CBOB from the list of 

obligated fuels or the direct transfer 

approach to RIN distribution could both 

accomplish the same goal, we request 

comment on which one would be more 

appropriate, if any. 

We have also considered a number of 

alternative approaches that could be 

used to help ensure that obligated 

parties can demonstrate compliance. For 

instance, one alternative approach 

would leave our proposed definitions 

for obligated parties in place, but would 

add a regulatory requirement that any 

party who blends ethanol into RBOB or 

CBOB must transfer the RINs associated 

with the ethanol to the original 

producer of the RBOB or CBOB. 

However, we believe that such an 

approach would be both inappropriate 

and difficult to implement. RBOB and 

CBOB is often transferred between 

multiple parties prior to ethanol 

blending. As a result, a regulatory 

requirement for RIN transfers back to 

the original producer would necessitate 

an additional tracking requirement for 

RBOB and CBOB so that the blender 

would know the identity of the original 

producer. It would also be difficult to 

ensure that RINs representing the 

specific category of renewable fuel 

blended were transferred to the 

producer of the RBOB or CBOB, given 

the fungible nature of RINs assigned to 

batches of renewable fuel. For these 

reasons, we do not believe that this 

alternative approach would be 

appropriate. 

In another alternative approach, some 

RINs that expire without being used for 

compliance by an obligated party could 

be used to reduce the nationwide 

volume of renewable fuel required in 

the following year. We would only 

reduce the required volume of 

renewable fuel to the degree that 

sufficient RINs had been generated to 

permit all obligated parties to 

demonstrate compliance, but some 

obligated parties nevertheless could not 

acquire a sufficient number of RINs. 

Moreover, only RINs that were expiring 

would be used to reduce the nationwide 

volume for the next year. This 

alternative approach would ensure that 

the volumes required in the statute 

would actually be produced and would 

prevent the hoarding of RINs from 

driving up demand for renewable fuel. 

However, it would also reduce the 

impact of the valid life limit for RINs. 

We could lower the 20% rollover cap 

applicable to the use of previous-year 

RINs to a lower value, such as 10%. 

This approach would provide a greater 

incentive for obligated parties with 

excess RINs to sell them but would 

further restrict a potentially useful 

means of managing an obligated party’s 

risk. As described in Section IV.D, we 

are not proposing any changes in the 

20% rollover cap in today’s notice. 

However, we request comment on it. 

Finally, another change to the 

program that would not change the 

definition of obligated parties, but could 

help address the disparity of access to 

RINs among obligated parties, would be 

to remove the requirement developed 

under RFS1 that RINs be transferred 

with renewable fuel volume by the 

renewable fuel producers and importers. 

This alternative is discussed further in 

Section III.H.4 below. 

H. Separation of RINs 

We propose that most of the RFS1 

provisions regarding the separation of 

RINs from volumes of renewable fuel be 

retained for RFS2. However, the 

modifications in EISA will require a 

number of changes, primarily to the 

treatment of RINs associated with 

nonroad renewable fuel and renewable 

fuels used in heating oil and jet fuel. 

Our approach to the separation of RINs 

by exporters must also be modified to 

account for the fact that there would be 

four categories of renewable fuel under 

RFS2. 

1. Nonroad 

Under RFS1, RINs associated with 

renewable fuels used in nonroad 

vehicles and engines downstream of the 

renewable fuel producer are required to 

be retired by the party who owns the 

renewable fuel at the time of blending. 

This provision derived from the EPAct 

definition of renewable fuel which was 

limited to fuel used to replace fossil fuel 

used in a motor vehicle. EISA however 

expands the definition of renewable 

fuel, and ties it to the definition of 

transportation fuel, which is defined as 

any ‘‘fuel for use in motor vehicles, 

motor vehicle engines, nonroad 

vehicles, or nonroad engines (except for 

ocean-going vessels). To implement 

these changes, the proposed RFS2 

program eliminates the RFS1 RIN 

retirement requirement for renewable 

fuels used in nonroad applications, with 

the exception of RINs associated with 

renewable fuels used in ocean-going 

vessels. 

2. Heating Oil and Jet Fuel 

EISA defined ‘additional renewable 

fuel’ as ‘‘fuel that is produced from 

renewable biomass and that is used to 

replace or reduce the quantity of fossil 

fuel present in home heating oil or jet 

fuel.’’ 40 While we are proposing that 

fossil-based heating oil and jet fuel 

would not be included in the fuel used 

by a refiner or importer to calculate 

their RVO, we are proposing that 

renewable fuels used as or in heating oil 

and jet fuel may generate RINs for credit 

purposes. Thus, the RINs of a renewable 

fuel, such as biodiesel, that is blended 

into heating oil continue to be valid. See 

also discussion in Section III.B.1.e. 

3. Exporters 

Under RFS1, exporters are assigned 

an RVO representing the volume of 

renewable fuel that has been exported, 

and they are required to separate all 

RINs that have been assigned to fuel that 

is exported. Since there is only one 

standard, there is only one possible 

RVO applicable to exporters. 

Under RFS2, there are four possible 

RVOs corresponding to the four 

categories of renewable fuel (cellulosic 

biofuel, biomass-based diesel, advanced 

biofuel, total renewable fuel). However, 

given the fungible nature of the RIN 

system and the fact that an assigned RIN 

transferred with a volume of renewable 

fuel may not be the same RIN that was 

originally generated to represent that 

volume, there is no way for an exporter 

to determine from an assigned RIN 

which of the four categories applies to 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24965 

an exported volume. In order to 

determine its RVOs, the only 

information available to the exporter is 

the type of renewable fuel that he is 

exporting. 

For RFS2, we are proposing that 

exporters use the fuel type and its 

associated volume to determine his 

applicable RVO. To accomplish this, an 

exporter must know which of the four 

renewable fuel categories applies to a 

given type of renewable fuel. We are 

proposing that all biodiesel (mono alkyl 

esters) and renewable diesel would be 

categorized as biomass-based diesel (D 

code of 4), and that exported volumes of 

these two fuels would be used to 

determine the exporter’s RVO for 

biomass-based diesel. For all other types 

of renewable fuel, the most likely 

category for most of the phase-in period 

of the RFS2 program is general 

renewable fuel, and as a result we 

propose that all other types of 

renewable fuel be used to determine the 

exporter’s RVO for total renewable fuel. 

Our proposed approach is provided at 

§ 80.1430. We recognize that by 2022 

the required volume of cellulosic 

biofuel will exceed the required volume 

of general renewable fuel that is in 

excess of the advanced biofuel 

requirements. Thus we request 

comment on requiring all or some 

portion of renewable fuels other than 

biodiesel and renewable diesel to be 

categorized as cellulosic biofuel in 2022 

and beyond. 

An alternative approach could be 

required that would more closely 

estimate the amount of exported 

renewable fuels that fall into the four 

categories defined by EISA. In this 

alternative, the total nationwide 

volumes required in each year (see 

Table II.A.1–1) would be used to 

apportion specific types of renewable 

fuel into each of the four categories. For 

example, exported ethanol may have 

originally been produced from cellulose 

to meet the cellulosic biofuel 

requirement, from corn to meet the total 

renewable fuel requirement, or may 

have been imported as advanced 

biofuel. If ethanol were exported, we 

could divide the exported volume into 

three RVOs for cellulosic biofuel, 

advanced biofuel, and total renewable 

fuel using the same proportions 

represented by the national volume 

requirements for that year. However, we 

believe that this alternative approach 

would add considerable complexity to 

the compliance determinations for 

exporters without necessarily adding 

more precision. Given the expected 

small volumes of exported renewable 

fuel, this added complexity does not 

seem warranted at this time. 

Nevertheless, we request comment on it. 

4. Alternative Approaches to RIN 

Transfers 

In the NPRM for the RFS1 

rulemaking, we presented a variety of 

approaches to the transfer of RINs, 

ultimately requiring that RINs generated 

by renewable fuel producers and 

importers must be assigned to batches of 

renewable fuel and transfered along 

with those batches. However, given the 

higher volumes required under RFS2 

and the resulting expansion in the 

number of regulated parties, we believe 

that two of the alternative approaches to 

RIN transfers should be considered for 

RFS2. Our proposal for an EPAmoderated RIN trading system (EMTS) 

may also support the implementation of 

one of these approaches. 

In one of the alternative approaches, 

we would entirely remove the 

restriction established under the RFS1 

rule requiring that RINs be assigned to 

batches of renewable fuel and 

transferred with those batches. Instead, 

renewable fuel producers could sell 

RINs (with a K code of 2 rather than 1) 

separately from volumes of renewable 

fuel to any party. This approach could 

significantly streamline the tracking and 

trading of RINs. For instance, there 

would no longer be a need for K-codes 

and restrictions on separation of RINs, 

there would only be a single RIN market 

rather than two (one for RINs assigned 

to volume and another for separated 

RINs), there would be no need for 

volume/RIN balance calculations at the 

end of each quarter, and there would be 

no need for restrictions on the number 

of RINs that can be transfered with each 

gallon of renewable fuel. As described 

more fully in Section III.B.4.b.ii, this 

approach could also provide a greater 

incentive for producers to demonstrate 

that the renewable biomass definition 

has been met for their feedstocks. As 

discussed in Section III.G.4, this 

approch could help level the playing 

field among obligated parties for access 

to RINs regardless of whether they 

market a substantial volume of gasoline 

or not. However, as discussed in the 

RFS1 rulemaking, this approach could 

also place obligated parties at greater 

risk of market manipulation by 

renewable fuel producers. 

In order to address some of the 

concerns raised about allowing 

producers and importers to separate 

RINs from their volume, in the NPRM 

for the RFS1 rulemaking we also 

presented an alternative concept for RIN 

distribution in which producers and 

importers of renewable fuels would be 

required to transfer the RIN, but only to 

an obligated party (see 71 FR 55591). 

This ’’direct transfer’’ approach would 

require renewable fuel producers to 

transfer RINs with renewable fuel for all 

transactions with obligated parties, and 

sell all other RINs directly to obligated 

parties on a quarterly basis for any 

renewable fuel volumes that were not 

sold directly to obligated parties. Only 

renewable fuel producers, importers, 

and obligated parties would be allowed 

to own RINs, and only obligated parties 

could take ownership of RINs from 

producers and importers. This approach 

would spare marketers and distributors 

of renewable fuel from the burdens 

associated with transferring RINs with 

batches, and thus would eliminate the 

tracking, recordkeeping and reporting 

requirements that would continue to be 

applicable to them if RINs are 

transferred through the distribution 

system as required under the RFS1 

program. 

Under the direct transfer alternative, 

the renewable fuel producer or importer 

would be required to transfer the RINs 

associated with his renewable fuel to an 

obligated party who purchases the 

renewable fuel. The RINs associated 

with any renewable fuel that is not 

directly transferred to an obligated party 

would not be transferred with the fuel 

as required under the RFS1 program. 

Instead, the renewable fuel producer or 

importer would be required to sell the 

RINs directly to an obligated party. Any 

RINs not sold in this way would be 

required to be offered for sale to all 

obligated parties through a public 

auction. This could be through an EPA 

moderated trading system, an existing 

internet auction web site, or through 

another auction mechanism 

implemented by a renewable fuel 

producer. 

Although we believe that the direct 

transfer approach has merit, many of the 

concerns laid out in the RFS1 NPRM 

remain valid today. In particular, the 

auctions would need to be regulated in 

some way to ensure that RIN generators 

could not withhold RINs from the 

market by such means as failing to 

adequately advertise the time and 

location of an auction, by setting the 

selling price too high, by specifying a 

minimum number of bids before selling, 

by conducting auctions infrequently, by 

having unduly short bidding windows, 

etc. We seek comment on how we could 

regulate such auctions to ensure that 

obligated parties could acquire 

sufficient RINs for compliance purposes 

in a timely manner. 

Our proposed EPA-moderated RIN 

trading system (see Section IV.E) could 

help to make the direct transfer 

approach feasible. By creating accounts 

24966 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

41See U.S. Department of Labor, Bureau of Labor 

Statistics (BLS), Consumer Price Index Web site at: 

http://www.bls.gov/cpi/. 

in a centralized system within which all 

RIN transfers between parties would be 

made, it may be more straightforward 

for obligated parties to identify available 

RINs owned by producers and 

importers, and to bid on those RINs. 

Therefore, while we are not proposing 

the direct transfer approach in today’s 

action, we nevertheless request 

comment on it. 

5. Neat Renewable Fuel and Renewable 

Fuel Blends Designated as 

Transportation Fuel, Home Heating Oil, 

or Jet Fuel 

Under RFS1, RINs must, with limited 

exceptions, be separated by an obligated 

party taking ownership of the renewable 

fuel, or by a party that blends renewable 

fuel with gasoline or diesel. In addition, 

a party that designates neat renewable 

fuel as motor vehicle fuel may separate 

RINs associated with that fuel if the fuel 

is in fact used in that manner without 

further blending. For purposes of the 

RFS program, ‘‘neat renewable fuel’’ is 

defined in 80.1101(p) as ‘‘a renewable 

fuel to which only de minimis amounts 

of conventional gasoline or diesel have 

been added.’’ One exception to these 

provisions is that biodiesel blends in 

which diesel constitutes less than 20 

volume percent are ineligible for RIN 

separation by a blender. As noted in the 

preamble to the final RFS1 regulations, 

EPA understands that in the vast 

majority of cases, biodiesel is blended 

with diesel in concentrations of 80 

volume percent or less. 

However, in order to account for 

situations in which biodiesel blends of 

81 percent or greater may be used as 

motor vehicle fuel without ever having 

been owned by an obligated party, EPA 

is proposing to change the applicability 

of the RIN separation provisions for 

RFS2. EPA is proposing that 

80.1429(b)(4) allow for separation of 

RINs for neat renewable fuel or blends 

of renewable fuel and or diesel fuel that 

the party designates as transportation 

fuel, home heating oil, or jet fuel, 

provided the neat renewable fuel or 

blend is used in the designated form, 

without further blending, as 

transportation fuel, home heating oil, or 

jet fuel. As in RFS1, those parties that 

blend renewable fuel with gasoline or 

diesel fuel (in a blend containing less 

than 80 percent biodiesel would in all 

cases be required to separate RINs 

pursuant 80.1429(b)(2). 

Thus, for example, under these 

proposed regulations, if a party intends 

to separate RINs from a volume of B85, 

the party must designate the blend for 

use as transportation fuel, home heating 

oil, or jet fuel and the blend must be 

used in its designated form without 

further blending. The party would also 

be required maintain records of this 

designation pursuant to 80.1451(b)(5). 

Finally, the party would be required to 

comply with the proposed PTD 

requirements in 80.1453(a)(5)(iv), which 

serve to notify downstream parties that 

the volume of fuel has been designated 

for use as transportation fuel, home 

heating oil, or jet fuel, and must be used 

in that designated form without further 

blending. Parties could separate RINs at 

the time they complied with the 

designation and PTD requirements, and 

would not need to physically track 

ultimate fuel use. 

EPA requests comment on this 

proposed approach to RIN separation. 

Additionally, EPA requests comment on 

an alternative approach to modifying 

the current program for separation of 

RINs. Under this second approach, 

80.1429(b)(2) and (b)(5)would be 

eliminated as redundant, and 

80.1429(b)(4) would be broadened to 

require separation of RINs for all neat 

renewable fuels and all blends of 

renewable fuels with either gasoline or 

diesel, when a party designates such 

fuel as transportation fuel, home heating 

oil or jet fuel, and the fuel is in fact used 

in accordance with that designation 

without further blending. The party 

would be required to maintain records 

that verify the ultimate use of the fuel 

as transportation, home heating, or jet 

fuel. Additionally, there would be a 

PTD requirement to inform downstream 

parties that the fuel has been designated 

as transportation, home heating, or jet 

fuel and may not be further blended. 

This proposed approach would 

eliminate the need for parties to 

distinguish for purposes of separating 

RINs between fuels that are neat or 

blended or, for biodiesel, between 

blends of E80 and below or E81 and 

above. 

I. Treatment of Cellulosic Biofuel 

1. Cellulosic Biofuel Standard 

EISA requires in section 202(e) that 

the Administrator set the cellulosic 

biofuel standard each November for the 

next year based on the lesser of the 

volume specified in the Act or the 

projected volume of cellulosic biofuel 

production for that year. In the event 

that the projected volume is less than 

the amount required in the Act, EPA 

may also reduce the applicable volume 

of the advanced biofuels requirement by 

the same or a lesser volume. We intend 

to examine EIA’s projected volumes and 

other available data including the 

production outlook reports proposed in 

Section III.K to be submitted to the EPA 

to decide the appropriate standard for 

the following year. The outlook reports 

from all renewable fuel producers 

would assist EPA in determining what 

the cellulosic biofuel standard should 

be and if the advanced biofuel standard 

should be adjusted. For years where 

EPA determines that the projected 

volume of cellulosic biofuels is not 

sufficient to meet the levels in EISA we 

will consider the availability of other 

advanced biofuels in deciding whether 

to lower the advanced biofuel standard 

as well. 

2. EPA Cellulosic Allowances for 

Cellulosic Biofuel 

Whenever EPA sets the cellulosic 

biofuel standard at a level lower than 

that required in EISA, EPA is required 

to provide a number of cellulosic credits 

for sale that is no more than the volume 

used to set the standard. Congress also 

specified the price for such credits: 

adjusted for inflation, they must be 

offered at the price of the higher of 25 

cents per gallon or the amount by which 

$3.00 per gallon exceeds the average 

wholesale price of a gallon of gasoline 

in the United States. The inflation 

adjustment will be for years after 2008. 

We propose that the inflation 

adjustment would be based on the 

Consumer Price Index for All Urban 

Consumers (CPI–U) for All Items 

expenditure category as provided by the 

Bureau of Labor Statistics.41

Congress afforded the Agency 

considerable flexibility in implementing 

the system of cellulosic biofuel credits. 

EISA states EPA; ‘‘shall include such 

provisions, including limiting the 

credits’ uses and useful life, as the 

Administrator deems appropriate to 

assist market liquidity and 

transparency, to provide appropriate 

certainty for regulated entities and 

renewable fuel producers, and to limit 

any potential misuse of cellulosic 

biofuel credits to reduce the use of other 

renewable fuels, and for such other 

purposes as the Administrator 

determines will help achieve the goals 

of this subsection.’’ 

Though EISA gives EPA broad 

flexibility, we believe the best way to 

accomplish the goals of providing 

certainty to both the cellulosic biofuel 

industry and the obligated parties is to 

propose credits with few degrees of 

freedom. We believe this would prevent 

speculation in the market and provide 

certainty for investments in real 

cellulosic biofuels. 

Specifically, we propose that the 

credits would be called allowances so 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24967 

42More information on wholesale gasoline prices 

can be found on the Department of Energy’s (DOE), 

Energy Information Administration’s (EIA) Web site 

at: http://tonto.eia.doe.gov/dnav/pet/ 

pet_pri_allmg_d_nus_PBS_cpgal_m.htm. 

that there is no confusion with RINs, 

such allowances would only be 

available for the current compliance 

year for which we have waived some 

portion of the cellulosic biofuel 

standard, they would only be available 

to obligated parties, and they would be 

nontransferable and nonrefundable. 

Further, we propose that obligated 

parties would only be able to purchase 

allowances up to the level of their 

cellulosic biofuel RVO less the number 

of cellulosic biofuel RINs that they own. 

This would help ensure that every party 

that needs to meet the cellulosic biofuel 

standard will have equal access to the 

allowances. A company would also then 

only use an allowance to meet its total 

renewable and advanced biofuel 

standards if it used the allowance for 

the cellulosic biofuel standard. We 

believe that if a company can only 

purchase as many allowances as it 

needs to meet its cellulosic biofuel 

obligation, it can not hinder another 

obligated party from meeting the 

standard and therefore every company 

that needs to meet the standard will 

have equal access to the allowances in 

the event that they do not acquire 

sufficient cellulosic biofuel RINs. If we 

were to allow a company to purchase 

more allowances than they needed, 

another company may not be able to 

meet the standard which we believe was 

not the intent of Congress. 

We also propose that these allowances 

would be offered in a generic format 

rather than a serialized format, like 

RINs. Allowances would be purchased 

from the EPA at the time that an 

obligated party submits its annual 

compliance demonstration to the EPA 

and establishes that it owns insufficient 

cellulosic biofuel RINs to meet its 

cellulosic biofuel RVO. A company 

owning cellulosic biofuel RINs and 

cellulosic allowances may use both 

types of credits if desired to meet their 

RVOs, but unlike RINs they would not 

be able to carry allowances over to the 

next calendar year. 

Congress refers to allowances as 

‘‘cellulosic biofuel credits,’’ with no 

indication that the ‘‘credits’’ should be 

given any less role in meeting a party’s 

obligations under the CAA section 

211(o) than would the purchase and use 

of a cellulosic biofuel RIN that reflects 

actual production and use of cellulosic 

biofuel. Because cellulosic biofuel RINs 

can be used to meet the advanced 

biofuel and total renewable fuel 

standards in addition to the cellulosic 

biofuel standard, we propose that 

cellulosic biofuel allowances also be 

available for use in meeting those three 

standards. 

We propose that the wholesale price 

of gasoline will be based on the average 

monthly bulk (refinery gate) price of 

gasoline using data from the most recent 

twelve months of data from EIA’s 

annual cellulosic ethanol forecast each 

October.42 Thus we will set the 

allowance price for the following year 

each November along with the 

cellulosic biofuel standard for the 

following year. We seek comment on 

using the average monthly rack 

(terminal) price for the same period and 

changing the allowance price as often as 

quarterly. Though EISA allows EPA to 

change the price as often as quarterly we 

believe this will lead to speculation 

which may introduce more uncertainty 

for the obligated parties and the 

cellulosic biofuel industry. 

3. Potential Adverse Impacts of 

Allowances 

While the credit provisions of section 

202(e) of EISA ensure that there is a 

predictable upper limit to the price that 

cellulosic biofuel producers can charge 

for a gallon of cellulosic biofuel and its 

assigned RIN, there may be 

circumstances in which this provision 

has other unintended impacts. For 

instance, if we made all cellulosic 

allowances available to any obligated 

party, one obligated party could 

purchase more allowances than he 

needs to meet his cellulosic biofuel RVO 

and then sell the remaining allowances 

at an inflated price to other obligated 

parties. Thus, we are proposing that 

each obligated party could only 

purchase allowances from the EPA up to 

the level of their cellulosic biofuel RVO. 

However, even with this restriction an 

obligated party could still purchase both 

cellulosic biofuel volume with its 

assigned RINs sufficient to meet its 

cellulosic biofuel RVO, and also 

purchase allowances from the EPA. In 

this case, the obligated party would 

effectively be using allowances as a 

replacement for corn ethanol rather than 

cellulosic biofuel. To prevent this, we 

are proposing an additional restriction: 

an obligated party could only purchase 

allowances from the EPA to the degree 

that it establishes it owns insufficient 

cellulosic biofuel RINs to meet its 

cellulosic biofuel RVO. This approach 

forces obligated parties to apply all their 

cellulosic biofuel RINs to their 

cellulosic biofuel RVO before appying 

any allowances to their cellulosic 

biofuel RVO. 

However, even with these proposed 

restrictions on the purchase and 

application of allowances, the statutory 

provision may not operate as intended. 

For instance, if the combination of 

cellulosic biofuel volume price and RIN 

price is low compared to that for cornethanol, a small number of obligated 

parties could purchase more cellulosic 

biofuel than they need to meet their 

cellulosic biofuel RVOs and could use 

the additional cellulosic biofuel RINs to 

meet their advanced biofuel and total 

renewable fuel RVOs. Other obligated 

parties would then have no access to 

cellulosic biofuel volume nor cellulosic 

biofuel RINs, and would be forced to 

purchase allowances from the EPA. This 

situation would have the net effect of 

allowances replacing imported 

sugarcane ethanol and/or corn-ethanol 

rather than cellulosic biofuel. 

Moreover, under certain conditions it 

may be possible for the market price of 

corn-ethanol RINs to be significantly 

higher than the market price of 

cellulosic biofuel RINs, as the latter is 

limited in the market by the price of 

EPA-generated allowances according to 

the statutory formula described in 

Section III.I.2 above. Under some 

conditions, this could result in a 

competitive disadvantage for cellulosic 

biofuel in comparison to corn ethanol. 

For instance, if gasoline prices at the 

pump are significantly higher than 

ethanol production costs, while at the 

same time corn-ethanol production 

costs are lower than cellulosic ethanol 

production costs, profit margins for 

corn-ethanol producers would be larger 

than for cellulosic ethanol producers. 

Under these conditions, while obligated 

parties may still purchase cellulosic 

ethanol volume and its associated RIN 

rather than allowances, cellulosic 

ethanol producers would realize lower 

profits than corn-ethanol producers due 

to the upper limit placed on the price 

of cellulosic biofuel RINs through the 

pricing formula for allowances. For a 

newly forming and growing cellulosic 

biofuel industry, this competitive 

disadvantage could make it more 

difficult for investors to secure funding 

for new projects, threatening the ability 

of the industry to reach the statutorily 

mandated volumes. 

We have not established the 

likelihood that these circumstances 

would arise in practice, and we request 

comment on the specific market 

conditions that could lead to them. 

Nevertheless, we have explored a 

variety of ways that we could modify 

the RFS program structure to mitigate 

these potential negative outcomes. For 

instance, as mentioned in Section III.I.2 

above, we are proposing that each 

24968 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

43The cellulosic biofuel RIN would be a 

separated RIN with a K code of 2 immediately upon 

generation. 

cellulosic allowance could be used to 

meet an obligated party’s RVOs for 

cellulosic biofuel, advanced biofuel, and 

total renewable fuel. However, we could 

restrict the applicability of allowances 

to only the cellulosic biofuel RVO. This 

approach could help ensure that 

demand for imported sugarcane ethanol 

and corn ethanol does not fall in the 

event that a small number of obligated 

parties purchase all available cellulosic 

biofuel volume, compelling the 

remaining obligated parties to purchase 

allowances. However, this approach 

could also have the effect of making the 

advanced biofuel and total renewable 

fuel standards more stringent. This 

could occur as obligated parties are 

forced to buy additional imported 

sugarcane ethanol and corn ethanol to 

make up for the fact that the allowances 

they purchase from the EPA would not 

apply to the advanced biofuel and total 

renewable fuel standards. 

As a variation to this approach, while 

still restricting the applicability of 

allowances to only the cellulosic biofuel 

RVO, we could similarly make 

cellulosic biofuel RINs applicable to 

only the cellulosic biofuel RVO. This 

approach would ensure that the 

compliance value of both cellulosic 

biofuel RINs and allowances is the 

same, but would necessarily result in an 

increase in the effective stringency of 

the advanced biofuel and total 

renewable fuel standards. 

Finally, we could institute a ‘‘dual 

RIN’’ approach to cellulosic biofuel that 

has the potential to address some of the 

shortcomings of the previous 

approaches. In this approach, both 

cellulosic biofuel RINs (with a D code 

of 1) and allowances could only be 

applied to an obligated party’s cellulosic 

biofuel RVO, but producers of cellulosic 

biofuel would also generate an 

additional RIN representing advanced 

biofuel (with a D code of 3). The 

producer would only be required to 

transfer the advanced biofuel RIN with 

a batch of cellulosic biofuel, and could 

retain the cellulosic biofuel RIN for 

separate sale to any party.43 The 

cellulosic biofuel and its attached 

advanced biofuel RIN would then 

compete directly with other advanced 

biofuel and its attached advanced 

biofuel RIN, while the separate 

cellulosic biofuel RIN would have an 

independent market value that would be 

effectively limited by the pricing 

formula for allowances as described in 

Section III.I.2. However, this approach 

would be a more significant deviation 

from the RIN generation and transfer 

program structure that was developed 

cooperatively with stakeholders during 

RFS1. It would provide cellulosic 

biofuel producers with significantly 

more control over the sale and price of 

cellulosic biofuel RINs, which was one 

of the primary concerns of obligated 

parties during the development of RFS1. 

Due to the drawbacks of each of these 

potential changes to the RFS program 

structure, we are not proposing any of 

them in today’s NPRM. However, we 

request comment on whether any of 

them, or alternatives, could address the 

adverse situations described above. We 

also request comment on the degree to 

which the adverse situations are likely 

to occur, and the degree of severity of 

the negative impacts that could result. 

J. Changes to Recordkeeping and 

Reporting Requirements 

1. Recordkeeping 

As with the existing renewable fuel 

standard program, recordkeeping under 

this proposed program will support the 

enforcement of the use of RINs for 

compliance purposes. As with the 

existing renewable fuels program, we 

are proposing that parties be afforded 

significant freedom with regard to the 

form that product transfer documents 

(PTDs) take. We propose to permit the 

use of product codes as long as they are 

understood by all parties. We propose 

that product codes may not be used for 

transfers to truck carriers or to retailers 

or wholesale purchaser-consumers. We 

propose that parties must keep copies of 

all PTDs they generate and receive, as 

well as copies of all reports submitted 

to EPA and all records related to the 

sale, purchase, brokering or transfer or 

RINs, for five (5) years. We also propose 

that parties must also keep copies of 

records that relate to flexibilities, as 

described in Section IV.A. through C. of 

this preamble. Such flexibilities are 

related to attest engagements, the 

upward delegation of RIN-separating 

responsibilities, and various small 

business oriented provisions. Upon 

request, parties would be responsible for 

providing their records to the 

Administrator or the Administrator’s 

authorized representative. We would 

reserve the right to request to receive 

documents in a format that we can read 

and use. 

In Section IV.E. of this preamble, we 

propose an EPA-Moderated Trading 

System for RINs. If adopted, the new 

system would allow for real-time 

reporting of RIN generation (i.e., batch 

reports by producers and importers) and 

RIN transactions. 

2. Reporting 

Under the existing renewable fuels 

program, obligated parties, exporters of 

renewable fuel, producers and importers 

of renewable fuels, and any party who 

owns RINs must report appropriate 

information to EPA on a quarterly and/ 

or annual basis. We are proposing a 

change in the schedule for submission 

of producers’ and importers’ batch 

reports, and for the submission of RIN 

transaction reports. This proposed 

change in schedule, which is discussed 

in great detail in Section IV.E. of this 

preamble, is effective for 2010 only. We 

are proposing that, for 2010, these 

reports (which were submitted quarterly 

under RFS1) be submitted monthly 

rather than quarterly. The reason for 

proposing monthly reporting for 2010 is 

to minimize difficulties associated with 

invalid RINs, while the EPA-Moderated 

Trading System is still under 

development. As described in detail in 

IV.E. we intend to have an EPAModerated Trading System fully 

operational by 2011. At the time that 

system becomes fully operational, all 

batch and RIN transactional reporting 

would be submitted in real time. The 

following deadlines would apply to 

‘‘real time,’ monthly, quarterly, and 

annual reports. 

‘‘Real time’’ reports within the EPAModerating Trading System would be 

submitted within three (3) business days 

of a reportable event (e.g. generation of 

a RIN, a transaction occurring involving 

a RIN). Real time reporting would apply 

to batch reports submitted by producers 

and importers who generate RINs and to 

to RIN transaction reports submitted in 

2011 and future years. 

Monthly reports would be submitted 

according to the following schedule: 

TABLE III.J.2–1—MONTHLY

REPORTING SCHEDULE

Month covered by 

report Due date for report 

January ..................... February 28. 

February .................... March 31. 

March ........................ April 30. 

April ........................... May 31. 

May ........................... June 30. 

June .......................... July 31. 

July ............................ August 31. 

August ....................... September 30. 

September ................. October 31. 

October ..................... November 30. 

November .................. December 31. 

December .................. January 31. 

The monthly reporting schedule 

would apply to batch reports submitted 

by producers and importers who 

generate RINs and to RIN transaction 

reports submitted for 2010 only. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24969 

Quarterly reports would be submitted 

on the following schedule: 

TABLE III.J.–2—QUARTERLY

REPORTING SCHEDULE

Quarter covered by 

report 

Due date for 

report 

January–March .............. May 31. 

April–June ..................... August 31. 

July–September ............ November 30. 

October–December ....... February 28. 

Quarterly reports include summary 

reports related to RIN activities. 

Annual reports (covering January 

through December) would continue to 

be due on February 28. Annual reports 

include compliance demonstrations by 

obligated parties. 

Under this proposed rule, the 

universe of reporting parties would 

grow, but we propose similar reporting 

to existing reporting. We believe that the 

proposed EPA-Moderating Trading 

System will make reporting easier for 

most parties. Existing reporting forms 

and instructions are posted at http:// 

www.epa.gov/otaq/regs/fuels/ 

rfsforms.htm. You may wish to refer to 

these existing forms in preparing your 

comments on this proposal. 

Simplified, secure reporting is 

currently available through our Central 

Data Exchange (CDX). CDX permits us 

to accept reports that are electronically 

signed and certified by the submitter in 

a secure and robustly encrypted fashion. 

Using CDX eliminates the need for wet 

ink signatures and reduces the reporting 

burden on regulated parties. It is our 

intention to continue to encourage the 

use of CDX for reporting under this 

proposed program as well. 

Due to the criteria that renewable fuel 

producers and importers must meet in 

order to generate RINs under RFS2, and 

due to the fact that renewable fuel 

producers and importers must have 

documentation about whether their 

feedstock(s) meets the definition of 

‘‘renewable biomass,’’ we propose 

several changes to the RFS1 RIN 

generation report. We propose to make 

the report a more general report on 

renewable fuel production in order to 

capture information on all batches of 

renewable fuel, whether or not RINs are 

generated for them. All renewable fuel 

producers and importers above 10,000 

gallons per year would report to EPA on 

each batch of their fuel and indicate 

whether or not RINs are generated for 

the batch. If RINs are generated, the 

producer or importer would be required 

to certify that his feedstock meets the 

definition of ‘‘renewable biomass.’’ If 

RINs are not generated, the producer or 

importer would be required to state the 

reason for not generating RINs, such as 

they have documentation that states that 

their feedstock did not meet the 

definition of ‘‘renewable biomass,’’ or 

the fuel pathway used to produce the 

fuel was such that the fuel did not 

qualify for any D code (see Section 

III.B.4.b for a discussion about 

demonstrating whether or not feedstock 

meets the definition of ‘‘renewable 

biomass’’). For each batch of renewable 

fuel produced, we also propose to 

require information about the types and 

volumes of feedstock used and the types 

and volumes of co-products produced, 

as well as information about the process 

or processes used. This information is 

necessary to confirm that the producer 

or importer assigned the appropriate D 

code to their fuel and that the D code 

was consistent with their registration 

information. 

Two minor additions are being 

incorporated into the RIN transaction 

report. First, for reports of RINs assigned 

to a volume of renewable fuel, we are 

asking that the volume of renewable fuel 

be reported. Additionally, we propose 

that RIN price information be submitted 

for transactions involving both 

separated RINs and RINs assigned to a 

renewable volume. This information is 

not collected under RFS1, but we 

believe this information has great 

programmatic value to EPA because it 

may help us to anticipate and 

appropriately react to market 

disruptions and other compliance 

challenges, will be beneficial when 

setting future renewable standards, and 

will provide additional insight into the 

market when assessing potential 

waivers. We anticipate that having 

current market information such as total 

number of RINs produced and RINs 

available in the separated market is 

incomplete. Missing is our ability to 

assess the general health and direction 

of the market and overall liquidity of 

RINs. Tracking price trend information 

will allow us to identify market 

inefficiencies and perceptions of RIN 

supply. When price information is 

combined with information from the 

production outlook reports, we will be 

better able to judge realistic 

expectations of renewable production 

and be in a better position when setting 

and justifying future renewable 

standards or pursuing relief through 

waiver provisions. Also, we believe the 

addition of price information will be 

highly beneficial to regulated parties. 

With price information being noted on 

transaction reports, buyers and sellers 

will have an additional and immediate 

reference when confirming transactions. 

Additionally, we believe that highly 

summarized price information (e.g., the 

average price of RINs traded) should be 

available to regulated parties, as well, 

and may help them to anticipate and 

avoid market disruptions. 

We also propose to make minor 

changes to compliance reports related to 

the identification of types of RINs. 

Please refer to Section III.B. of this 

preamble for a discussion of types of 

renewable fuels. Also, please refer to 

Section III.A. for a discussion of 

proposed changes to RINs. 

Under our proposed EPA-Moderated 

Trading System described in Section 

IV.E. of this preamble, then there would 

be a change in reporting burden on 

regulated parties that affects the 

frequency of reporting and the number 

of reports. Instead of quarterly and/or 

annual contact with EPA, there would 

be real time contact—i.e., as batches of 

renewable fuel are generated or as RINs 

are transacted. However, we believe that 

any burden is offset by the advantage of 

having a simplified system for RIN 

management that will promote the 

integrity of RINs and will remove 

‘‘guesswork’’ now associated with RIN 

management. As things are now, a 

regulated party may experience 

frustration and incur expense in trying 

to track down and correct errors. Once 

an error is made, it propagates 

throughout the distribution system with 

each transfer from party to party. By 

having EPA moderate RIN management, 

we believe that errors would be 

minimized and regulated parties would 

be freed of the greater burden to attempt 

to track down and correct errors they 

may have made. Implementation of the 

EPA-Moderated Trading System would 

correspond to real-time reporting of the 

type of information contained in the 

following two quarterly reports: The 

Renewable Fuel Production Report, 

known as the RIN Generation Report or 

‘‘batch report’’ under RFS1 (Report 

Form Template RFS0400), and the RIN 

Transaction Report (Report Form 

Template RFS0200), starting in 2011. 

For 2010, we are proposing that the type 

of information contained in these two 

forms be submitted monthly. These and 

other reports and instructions related to 

the existing renewable fuel standard 

program (RFS1) are posted at http:// 

www.epa.gov/otaq/regs/fuels/ 

rfsforms.htm. 

3. Additional Requirements for 

Producers of Renewable Natural Gas, 

Electricity, and Propane 

In addition to the general reporting 

requirement listed above, we are 

proposing an additional item of 

reporting for producers of renewable 

24970 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

natural gas, electricity, and propane 

who choose to generate and assign RINs. 

While producers of renewable natural 

gas, electricity, and propane who 

generate and assign RINs would be 

responsible for filing the same reports as 

other producers of RIN-generating 

renewable fuels, we propose that 

additional reporting for these producers 

be required to support the actual use of 

their products in the transportation 

sector. We believe that one simple way 

to achieve this may be to add a 

requirement that producers of 

renewable natural gas, electricity, and 

propane add the name of the purchaser 

(e.g., the name of the wholesale 

purchaser-consumer (WPC) or fleet) to 

their quarterly RIN generation reports 

and then maintain appropriate records 

that further identify the purchaser and 

the details of the transaction. We are not 

proposing that a purchaser who is either 

a WPC or an end user would have to 

register under this scenario, unless that 

party engages in other activities 

requiring registration under this 

program. 

K. Production Outlook Reports 

We are also proposing additional 

reporting—annual production outlook 

reports that would be required of all 

domestic renewable fuel producers, 

foreign renewable fuel producers who 

register to generate RINs, and importers 

of covered renewable fuels starting in 

2010. These production outlook reports 

would be similar to the pre-compliance 

reports required under the Highway and 

Nonroad Diesel programs. These reports 

would contain information about 

existing and planned production 

capacity, long-range plans, and 

feedstocks and production processes to 

be used at each production facility. For 

expanded production capacity that is 

planned or underway at each existing 

facility, or new production facilities that 

are planned or underway, the progress 

reports would require information on: 

(1) Strategic planning; (2) Planning and 

front-end engineering; (3) Detailed 

engineering and permitting; (4) 

Procurement and Construction; and (5) 

Commissioning and startup. These five 

project phases are described in EPA’s 

June 2002 Highway Diesel Progress 

Review report (EPA document number 

EPA420–R–02–016, located at: 

www.epa.gov/otaq/regs/hd2007/ 

420r02016.pdf). 

The full list of requirements for the 

proposed production outlook reports is 

provided in the proposed regulations at 

§ 80.1449. The information submitted in 

the reports would be used to evaluate 

the progress that the industry is making 

towards the renewable fuels volume 

goals mandated by EISA and to set the 

annual cellulosic biofuel, advanced 

biofuel, biomass-based diesel, and total 

renewable fuel standards (see Section 

II.A.7 of this preamble). We are 

proposing that the annual production 

outlook reports be due annually by 

February 28, beginning in 2010 and 

continuing through 2022, and we are 

proposing that each annual report must 

provide projected information through 

calendar year 2022. 

EPA currently receives data on 

projected flexible-fuel vehicle (FFV) 

sales and conversions from vehicle 

manufacturers; however, we do not have 

information on renewable fuels in the 

distribution system. Thus, EPA is also 

considering whether to require the 

annual submission of data to facilitate 

our evaluation of the ability of the 

distribution system to deliver the 

projected volumes of biofuels to 

petroleum terminals that are needed to 

meet the RFS2 standards. We request 

comment on the extent to which such 

information is already publicly available 

or can be purchased from a proprietary 

source. We further request comment on 

the extent to which such publicly 

available or purchasable data would be 

sufficient for EPA to make its 

determination. To the extent that 

additional data might be needed, we 

request comment on the parties that 

should be required to report to EPA and 

what data should be required. For 

example, would it be appropriate to 

require terminal operators to report to 

EPA annually on their ability to receive, 

store, and blend biofuels into 

petroleum-based fuels? We believe that 

publicly available information on E85 

refueling facilities is sufficient for us to 

make a determination about the 

adequacy of such facilities to support 

the projected volumes of E85 that would 

be used to satisfy the RFS2 standards. 

We request comment on the proposed 

requirement of annual production 

outlook reports, and all other aspects 

mentioned above (e.g., reporting 

requirements, reporting dates, etc.). 

L. What Acts Are Prohibited and Who Is 

Liable for Violations? 

The prohibition and liability 

provisions applicable to the proposed 

RFS2 program would be similar to those 

of the RFS1 program and other gasoline 

programs. The proposed rule identifies 

certain prohibited acts, such as a failure 

to acquire sufficient RINs to meet a 

party’s RVOs, producing or importing a 

renewable fuel that is not assigned a 

proper RIN category (or D Code), 

improperly assigning RINs to renewable 

fuel that was not produced with 

renewable biomass, failing to assign 

RINs to qualifying fuel, or creating or 

transferring invalid RINs. Any person 

subject to a prohibition would be held 

liable for violating that prohibition. 

Thus, for example, an obligated party 

would be liable if the party failed to 

acquire sufficient RINs to meet its RVO. 

A party who produces or imports 

renewable fuels would be liable for a 

failure to assign proper RINs to 

qualifying batches of renewable fuel 

produced or imported. Any party, 

including an obligated party, would be 

liable for transferring a RIN that was not 

properly identified. 

In addition, any person who is subject 

to an affirmative requirement under this 

program would be liable for a failure to 

comply with the requirement. For 

example, an obligated party would be 

liable for a failure to comply with the 

annual compliance reporting 

requirements. A renewable fuel 

producer or importer would be liable for 

a failure to comply with the applicable 

batch reporting requirements. Any party 

subject to recordkeeping or product 

transfer document (PTD) requirements 

would be liable for a failure to comply 

with these requirements. Like other EPA 

fuels programs, the proposed rule 

provides that a party who causes 

another party to violate a prohibition or 

fail to comply with a requirement may 

be found liable for the violation. 

EPAct amended the penalty and 

injunction provisions in section 211(d) 

of the Clean Air Act to apply to 

violations of the renewable fuels 

requirements in section 211(o). 

Accordingly, under the proposed rule, 

any person who violates any prohibition 

or requirement of the RFS2 program 

may be subject to civil penalties of 

$32,500 for every day of each such 

violation and the amount of economic 

benefit or savings resulting from the 

violation. Under the proposed rule, a 

failure to acquire sufficient RINs to meet 

a party’s renewable fuels obligation 

would constitute a separate day of 

violation for each day the violation 

occurred during the annual averaging 

period. 

As discussed above, the regulations 

would prohibit any party from creating 

or transferring invalid RINs. These 

invalid RIN provisions apply regardless 

of the good faith belief of a party that 

the RINs are valid. These enforcement 

provisions are necessary to ensure the 

RFS2 program goals are not 

compromised by illegal conduct in the 

creation and transfer of RINs. 

As in other motor vehicle fuel credit 

programs, the regulations would address 

the consequences if an obligated party 

was found to have used invalid RINs to 

demonstrate compliance with its RVO. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24971 

44Small refineries are also allowed to waive this 

exemption. 

In this situation, the obligated party that 

used the invalid RINs would be required 

to deduct any invalid RINs from its 

compliance calculations. Obligated 

parties would be liable for violating the 

standard if the remaining number of 

valid RINs was insufficient to meet its 

RVO, and the obligated party might be 

subject to monetary penalties if it used 

invalid RINs in its compliance 

demonstration. In determining what 

penalty is appropriate, if any, we would 

consider a number of factors, including 

whether the obligated party did in fact 

procure sufficient valid RINs to cover 

the deficit created by the invalid RINs, 

and whether the purchaser was indeed 

a good faith purchaser based on an 

investigation of the RIN transfer. A 

penalty might include both the 

economic benefit of using invalid RINs 

and/or a gravity component. 

Although an obligated party would be 

liable under our proposed program for 

a violation if it used invalid RINs for 

compliance purposes, we would 

normally look first to the generator or 

seller of the invalid RINs both for 

payment of penalty and to procure 

sufficient valid RINs to offset the invalid 

RINs. However, if, for example, that 

party was out of business, then attention 

would turn to the obligated party who 

would have to obtain sufficient valid 

RINs to offset the invalid RINs. 

We request comment on the need for 

additional prohibition and liability 

provisions specific to the proposed RFS 

2 program. 

IV. What Other Program Changes Have 

We Considered? 

In addition to the regulatory changes 

we are proposing today in response to 

EISA that are designed to implement the 

provisions of RFS2, there are a number 

of other changes to the RFS program 

that we are considering. These changes 

would be designed to increase 

flexibility, simplify compliance, or 

address RIN transfer issues that have 

arisen since the start of the RFS1 

program. We have also investigated 

impacts on small businesses and are 

proposing approaches designed to 

address the impacts of the program on 

them. 

A. Attest Engagements 

The purpose of an attest engagement 

is to receive third party verification of 

information reported to EPA. An attest 

engagement, which is similar to a 

financial audit, is conducted by a 

Certified Public Accountant (CPA) or 

Certified Independent Auditor (CIA) 

following agreed-upon procedures. 

Under the RFS1 program, an attest 

engagement must be conducted 

annually. We propose to apply the same 

provision to this proposed RFS2 rule. 

However, we seek comment on whether 

there should be any flexibility 

provisions for those who own a small 

number of RINs and what level of 

flexibility might be appropriate (e.g., 

allowing those who own a small number 

of RINs to submit an attest engagement 

every two years, rather than every year). 

B. Small Refinery and Small Refiner 

Flexibilities 

1. Small Refinery Temporary Exemption 

CAA section 211(o)(8), enacted as part 

of EPAct, provides a temporary 

exemption to small refineries (those 

refineries with a crude throughput of no 

more than 75,000 barrels of crude per 

day, as defined in section 211(o)(1)(K)) 

through December 31, 2010.44

Accordingly, the RFS1 program 

regulations exempt gasoline produced 

by small refineries from the renewable 

fuels standard (unless the exemption 

was waived), see 40 CFR 80.1141. EISA 

did not alter the small refinery 

exemption in any way. Therefore, we 

intend to retain this small refinery 

temporary exemption in the RFS2 

program without change. Further, as 

discussed below in Section IV.B.2.c, we 

are proposing to continue one of the 

hardship provisions for small refineries 

provided at 40 CFR 80.1141(e). 

2. Small Refiner Flexibilities 

As mentioned above, EPAct granted a 

temporary exemption from the RFS 

program to small refineries through 

December 31, 2010. In the RFS1 final 

rule, we exercised our discretion under 

section 211(o)(3)(B) and extended this 

temporary exemption to the few 

remaining small refiners that met the 

Small Business Administration’s (SBA) 

definition of a small business (1,500 

employees or less company-wide) but 

did not meet the Congressional small 

refinery definition as noted above. 

As explained in the discussion of our 

compliance with the Regulatory 

Flexibility Act below in Section XII.C 

and in the Initial Regulatory Flexibility 

Analysis in Chapter 7 of the draft RIA, 

we considered the impacts of today’s 

proposed regulations on small 

businesses. Most of our analysis of small 

business impacts was performed as a 

part of the work of the Small Business 

Advocacy Review Panel (SBAR Panel, 

or ‘‘the Panel’’) convened by EPA, 

pursuant to the Regulatory Flexibility 

Act as amended by the Small Business 

Regulatory Enforcement Fairness Act of 

1996 (SBREFA). The Final Report of the 

Panel is available in the docket for this 

proposed rule. For the SBREFA process, 

we conducted outreach, fact-finding, 

and analysis of the potential impacts of 

our regulations on small businesses. 

During the SBREFA process, small 

refiners informed us that they would 

need to rely heavily on RINs and/or 

make capital improvements to comply 

with the RFS2 requirements. These 

refiners raised concerns about the RIN 

program itself, uncertainty (with the 

required renewable fuel volumes, RIN 

availability, and cost), and the desire for 

a RIN system review access to RINs, and 

the difficulty in raising capital and 

competing for engineering resources to 

make capital improvements. 

During the Panel process, EPA raised 

a concern regarding provisions for small 

refiners in the RFS2 rule; and this rule 

presents a very different issue than the 

small refinery versus small refiner 

concept from RFS1. This issue deals 

with whether or not EPA has the 

authority to provide a subset of small 

refineries (those that are operated by 

small refiners) with an extension of time 

that would be different from, and more 

than, the temporary exemption specified 

by Congress in section 211(o)(9) for 

small refineries (temporary exemption 

through December 31, 2010, with the 

potential for extensions of the 

exemption beyond this date if certain 

criteria are met.). In other words, the 

temporary exemption specified by 

Congress provided relief for those small 

refiners that are covered by the small 

refinery provision; EPA believes that 

providing these refiners with an 

additional exemption different from that 

provided by section 211(o)(9) may be 

inconsistent with the intent of Congress. 

Congress spoke directly to the relief that 

EPA may provide for small refineries, 

including those small refineries 

operated by small refiners, and limited 

it to a blanket exemption through 

December 31, 2010, with additional 

extensions if the criteria specified by 

Congress were met. 

The Panel recommended that EPA 

consider the issues raised by the SERs 

and discussions had by the Panel itself, 

and that EPA should consider 

comments on flexibility alternatives that 

would help to mitigate negative impacts 

on small businesses to the extent 

allowable by the Clean Air Act. A 

summary of further recommendations of 

the Panel are discussed in Section XII.C 

of this preamble, and a full discussion 

of the regulatory alternatives discussed 

and recommended by the Panel can be 

found in the SBREFA Final Panel 

Report. 

24972 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

a. Extension of Existing RFS1 

Temporary Exemption 

As previously stated, the RFS1 

program regulations provide small 

refiners who operate small refineries, as 

well as those small refiners who do not 

operate small refineries, with a 

temporary exemption from the 

standards through December 31, 2010. 

Small refiner SERs suggested that an 

additional temporary exemption for the 

RFS2 program would be beneficial to 

them in meeting the RFS2 standards; 

and the Panel recommended that EPA 

propose a delay in the effective date of 

the standards until 2014 for small 

entities, to the maximum extent allowed 

by the statute. 

We have evaluated an additional 

temporary exemption for small refiners 

for the required RFS2 standards, and we 

have also evaluated such an exemption 

with respect to our concerns about our 

authority to provide an extension of the 

temporary exemption for small 

refineries that is different from that 

provided in CAA section 211(o)(9). As 

a result, we believe that the limitations 

of the statute do not necessarily allow 

us the discretion to provide an 

exemption for small refiners only (i.e., 

small refiners but not small refineries) 

beyond that provided in section 

211(o)(9). However, it is important to 

recognize that the 211(o)(9) small 

refinery provision does allow for 

extensions beyond December 31, 2010, 

with two separate provisions addressing 

extensions beyond 2010. These 

provisions are discussed below in 

Section IV.B.2.c. 

Therefore, we are proposing to 

continue the temporary exemption 

finalized in RFS1—through December 

31, 2010—for small refineries and all 

qualified small refiners. We also request 

comment on the interpretation of our 

authority under the CAA and the 

appropriateness of providing an 

extension to small refiners only beyond 

that authorized by section 211(o)(9). 

b. Program Review 

During the SBREFA process, the small 

refiner SERs also requested that EPA 

perform an annual program review, to 

begin one year before small refiners are 

required to comply with the program. 

We have slight concerns that such a 

review could lead to some redundancy 

since EPA is required to publish a 

notice of the applicable RFS standards 

in the Federal Register annually, and 

this annual process will inevitably 

include an evaluation of the projected 

availability of renewable fuels. 

Nevertheless, some Panel members 

commented that they believe a program 

review could be beneficial to small 

entities in providing them some insight 

to the RFS program’s progress and 

alleviate some uncertainty regarding the 

RIN system. As we will be publishing a 

Federal Register notice annually, the 

Panel recommended that we include an 

update of RIN system progress (e.g., RIN 

trading, publicly-available information 

RIN availability, etc.) in this annual 

notice. 

We propose to include elements of 

RIN system progress—such as RIN 

trading and availability—in the annual 

Federal Register RFS2 standards notice. 

We also invite comment on additional 

elements to include in this review. 

c. Extensions of the Temporary 

Exemption Based on Disproportionate 

Economic Hardship 

As noted above, there are two 

provisions in section 211(o)(9) that 

allow for an extension of the temporary 

exemption beyond December 31, 2010. 

One involves a study by the Department 

of Energy (DOE) concerning whether 

compliance with the renewable fuel 

requirements would impose 

disproportionate economic hardship on 

small refineries, and would grant an 

extension of at least two years for a 

small refinery that DOE determines 

would be subject to such 

disproportionate hardship. Another 

provision authorizes EPA to grant an 

extension for a small refinery based 

upon disproportionate economic 

hardship, on a case-by-case basis. 

We believe that these avenues of relief 

can and should be fully explored by 

small refiners who are covered by the 

small refinery provision. In addition, we 

believe that it is appropriate to consider 

allowing petitions to EPA for an 

extension of the temporary exemption 

based on disproportionate economic 

hardship for those small refiners who 

are not covered by the small refinery 

provision (again, per our discretion 

under section 211(o)(3)(B)); this would 

ensure that all small refiners have the 

same relief available to them as small 

refineries do. Thus, we are proposing a 

hardship provision for small refineries 

in the RFS2 program, that any small 

refinery may apply for a case-by-case 

hardship at any time on the basis of 

disproportionate economic hardship per 

CAA section 211(o)(9)(B). While EISA 

stated (per section 211(o)(9)(A)(ii)(I)) 

that the small refinery temporary 

exemption shall be extended for at least 

two years for any small refinery that the 

DOE small refinery study determines 

would face disproportionate economic 

hardship in meeting the requirements of 

the RFS2 program, we are not proposing 

this hardship provision given the 

outcome of the DOE small refinery 

study (as discussed below). 

In the small refinery study, ‘‘EPACT 

2005 Section 1501 Small Refineries 

Exemption Study’’, DOE’s finding was 

that there is no reason to believe that 

any small refinery would be 

disproportionately harmed by inclusion 

in the proposed RFS2 program. This 

finding was based on the fact that there 

appeared to be no shortage of RINs 

available under RFS1, and EISA has 

provided flexibility through waiver 

authority (per section 211(o)(7)). 

Further, in the case of the cellulosic 

biofuel standard, cellulosic biofuel 

allowances can be provided from EPA at 

prices established in EISA (see proposed 

regulation section 80.1455). DOE thus 

determined that no small refinery would 

be subject to disproportionate economic 

hardship under the proposed RFS2 

program, and that the small refinery 

exemption should not be extended 

beyond December 31, 2010. DOE noted 

in the study that, if circumstances were 

to change and/or the RIN market were 

to become non-competitive or illiquid, 

individual small refineries have the 

ability to petition EPA for an extension 

of their small refinery exemption (as 

proposed at draft regulation section 

80.1441). We note that the findings of 

DOE’s small refinery study, and a 

consideration of EPA’s ongoing review 

of the functioning of the RIN market, 

could factor into the basis for approval 

of such a hardship request. 

We are also proposing a case-by-case 

hardship provision for those small 

refiners that do not operate small 

refineries, at draft regulation section 

80.1442(h), using our discretion under 

CAA section 211(o)(3)(B). This proposed 

provision would allow those small 

refiners that do not operate small 

refineries to apply for the same kind of 

extension as a small refinery. In 

evaluating applications for this 

proposed hardship provision, it was 

recommended by the SBAR Panel that 

EPA take into consideration information 

gathered from annual reports and RIN 

system progress updates. 

d. Phase-in 

The small refiner SERs suggested that 

a phase-in of the obligations applicable 

to small refiners would be beneficial for 

compliance, such that small refiners 

would comply by gradually meeting the 

standards on an incremental basis over 

a period of time, after which point they 

would comply fully with the RFS2 

standards, however we have concerns 

about our authority under the statute to 

allow for such a phase-in of the 

standards. CAA section 211(o)(3)(B) 

states that the renewable fuel obligation 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24973 

shall ‘‘consist of a single applicable 

percentage that applies to all categories 

of persons specified’’ as obligated 

parties. This kind of phase-in approach 

would result in different applicable 

percentages being applied to different 

obligated parties. Further, as discussed 

above, such a phase-in approach would 

provide more relief to small refineries 

operated by small refiners than that 

provided under the small refinery 

provision. We do not believe that we 

can use our discretion under the statute 

to allow for such a provision; however 

we invite comment on the concept of a 

phase-in provision for all small refiners. 

e. RIN-Related Flexibilities 

The small refiner SERs requested that 

the proposed rule contain provisions for 

small refiners related to the RIN system, 

such as flexibilities in the RIN rollover 

cap percentage and allowing all small 

refiners to use RINs interchangeably. 

Currently in the RFS program, up to 

20% of a previous year’s RINs may be 

‘‘rolled over’’ and used for compliance 

in the following year. A provision to 

allow for flexibilities in the rollover cap 

could include a higher RIN rollover cap 

for small refiners for some period of 

time or for at least some of the four 

standards. While the rollover cap is the 

means through which we are 

implementing the limited credit lifetime 

provisions in section 211(o) of the CAA, 

and therefore cannot simply be 

eliminated, the magnitude of the cap 

can be modified to some extent. Thus, 

there could be an opportunity to 

provide appropriate flexibility in this 

area. However, given the results of the 

DOE small refinery study, we do not 

believe it would be appropriate to 

propose a change to the RIN rollover cap 

for small refiners today. However, we 

request comment on the concept of 

increasing the RIN rollover cap 

percentage for small refiners. We also 

request comment on an appropriate 

level of that percentage. For example, 

would a rollover cap of 50% for small 

refiners be appropriate? Or, would an 

intermediate value between 20% and 

50%, such as 35%, be more 

appropriate? 

The Panel recommended that we take 

comment on allowing RINs to be used 

interchangeably for small refiners, but 

not propose this concept because under 

this approach small refiners would 

arguably be subject to a different 

applicable percentage than other 

obligated parties. However, this concept 

fails to require the four different 

standards mandated by Congress (e.g., 

conventional biofuel could not be used 

instead of cellulosic biofuel or biomassbased diesel), and is not consistent with 

section 211(o) of the Clean Air Act. 

Thus, we are not proposing this 

provision in this action, however we 

invite comment on such an approach for 

small refiners. 

C. Other Flexibilities 

1. Upward Delegation of RIN-Separating 

Responsibilities 

Since the start of the RFS1 program 

on September 1, 2007, there have been 

a number of instances in which a party 

who receives RINs with a volume of 

renewable fuel is required to either 

separate or retire those RINs, but views 

the recordkeeping and reporting 

requirements under the RFS program as 

an unnecessary burden. Such 

circumstances typically might involve a 

renewable fuel blender, a party that uses 

renewable fuel in its neat form, or a 

party that uses renewable fuel in a nonhighway application and is therefore 

required to retire the RINs (under RFS1) 

associated with the volume. In some of 

these cases, the affected party may 

purchase and/or use only small volumes 

of renewable fuel and, absent the RFS 

program, would be subject to few if any 

other EPA regulations governing fuels. 

This situation will become more 

prevalent with the RFS2 program, as 

EISA added diesel fuel to the RFS 

program. With the RFS1 rule, small 

blenders (generally farmers and other 

parties that use nonroad diesel fuel) 

blending small amounts of biodiesel 

were not covered under the rule as 

EPAct mandated renewable fuel 

blending for highway use only. EISA 

mandates certain amounts of renewable 

fuels to be blended into transportation 

fuels—which includes nonroad diesel 

fuel. Thus, parties that were not 

regulated under the RFS1 rule who only 

blend a small amount of renewable fuel 

(and, as mentioned above, are generally 

not subject to many of the EPA fuels 

regulations) would now be regulated by 

the program. 

Consequently, we believe it may be 

appropriate, and thus we are proposing 

today, to permit blenders who only 

blend a small amount of renewable fuel 

to allow the party directly upstream to 

separate RINs on their behalf. Such a 

provision would be consistent with the 

fact that the RFS1 program already 

allows marketers of renewable fuels to 

assign more RINs to some of their sold 

product and no RINs to the rest of their 

sold product. We believe that this 

provision would eliminate undue 

burden on small parties who would 

otherwise not be regulated by this 

program. We are proposing that this 

provision apply to small blenders who 

blend and trade less than 125,000 total 

gallons of renewable fuel per year. We 

also request comment on whether or not 

this threshold is appropriate. 

We envision that such a provision 

would be available to any blender who 

must separate RINs from a volume of 

renewable fuel under § 80.1429(b)(2). 

We also request comment on 

appropriate documentation to authorize 

this upward delegation. This could be 

something such as a document given to 

the supplier identifying the RIN 

separation that the supplier would 

perform. The document could include 

sufficient information to precisely 

identify the conditions of the 

authorization, such as the volume of 

renewable fuel in question and the 

number of RINs assigned to that volume. 

By necessity the document would need 

to be signed by both parties, and copies 

retained as records by both parties, 

since the supplier would then be 

responsible for these actions. The 

supplier would then be allowed to 

retain ownership of RINs assigned to a 

volume of renewable fuel when that 

volume is transferred, under the 

condition that the RINs be separated or 

retired concurrently with the transfer of 

the volume. We are proposing an annual 

authorization that would apply to all 

volumes of renewable fuel transferred 

between two parties for a given year 

(i.e., the two parties would enter into a 

contract stating that the supplier has 

RIN-separation responsibilities for all 

transferred volumes). 

We are proposing this provision 

solely for the case of blenders who 

blend and trade less than 125,000 total 

gallons of renewable fuel per year. A 

company that blends 100,000 gallons 

and trades 100,000 gallons would not be 

able to use this provision. However, we 

request comment on whether 

authorization to delegate RIN-separation 

responsibilities should also be allowed 

for other parties as well. 

2. Small Producer Exemption 

Under the RFS1 program, parties who 

produce or import less than 10,000 

gallons of renewable fuel in a year are 

not required to generate RINs for that 

volume, and are not required to register 

with the EPA if they do not take 

ownership of RINs generated by other 

parties. We propose to maintain this 

exemption under the RFS2 rule. 

However, we request comment on 

whether the 10,000 gallon threshold 

should be higher given that the total 

volume of renewable fuel mandated by 

EISA is considerably higher than that 

required by the RFS1 program, or 

conversely whether it should be lower 

given that the biomass-based diesel 

standard is considerably lower than the 

24974 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

mandated volume for total renewable 

fuel. 

D. 20% Rollover Cap 

EISA does not change the language in 

CAA section 211(o)(5) stating that 

renewable fuel credits must be valid for 

showing compliance for 12 months as of 

the date of generation. As discussed in 

the RFS1 final rulemaking, we 

interpreted the statute such that credits 

would represent renewable fuel 

volumes in excess of what an obligated 

party needs to meet their annual 

compliance obligation. Given that the 

renewable fuel standard is an annual 

standard, obligated parties determine 

compliance shortly after the end of the 

year, and credits would be identified at 

that time. In the context of our RINbased program, we have accomplished 

the statute’s objective by allowing RINs 

to be used to show compliance for the 

year in which the renewable fuel was 

produced and its associated RIN first 

generated, or for the following year. 

RINs not used for compliance purposes 

in the year in which they were 

generated will by definition be in excess 

of the RINs needed by obligated parties 

in that year, making excess RINs 

equivalent to the credits referred to in 

section 211(o)(5). Excess RINs are valid 

for compliance purposes in the year 

following the one in which they initially 

came into existence. RINs not used 

within their valid life will thereafter 

cease to be valid for compliance 

purposes. 

In the RFS1 final rulemaking, we also 

discussed the potential ‘‘rollover’’ of 

excess RINs over multiple years. This 

can occur in situations wherein the total 

number of RINs generated each year for 

a number of years in a row exceeds the 

number of RINs required under the RFS 

program for those years. The excess 

RINs generated in one year could be 

used to show compliance in the next 

year, leading to the generation of new 

excess RINs in the next year, causing the 

total number of excess RINs in the 

market to accumulate over multiple 

years despite the limit on RIN life. The 

rollover issue could in some 

circumstances undermine the ability of 

a limit on credit life to guarantee an 

ongoing market for renewable fuels. 

To implement the Act’s restriction on 

the life of credits and address the 

rollover issue, the RFS1 final 

rulemaking implemented a 20% cap on 

the amount of an obligated party’s RVO 

that can be met using previous-year 

RINs. Thus each obligated party is 

required to use current-year RINs to 

meet at least 80% of its RVO, with a 

maximum of 20% being derived from 

previous-year RINs. Any previous-year 

RINs that an obligated party may have 

that are in excess of the 20% cap can be 

traded to other obligated parties that 

need them. If the previous-year RINs in 

excess of the 20% cap are not used by 

any obligated party for compliance, they 

will thereafter cease to be valid for 

compliance purposes. 

EISA does not modify the statutory 

provisions regarding credit life, and the 

volume changes by EISA also do not 

change at least the possibility of large 

rollovers of RINs for individual 

obligated parties. Therefore, we propose 

to maintain the regulatory requirement 

for a 20% rollover cap under the new 

RFS2 program. However, under RFS2 

obligated parties will have four RVOs 

instead of one. As a result, we are 

proposing that the 20% rollover cap 

would apply separately to all four 

RVOs. We do not believe it would be 

appropriate to apply the rollover cap to 

only the RVO representing total 

renewable fuel, leaving the other three 

RVOs with no rollover cap. Doing so 

would allow all previous-year RINs 

used for compliance to be those with a 

D code of 4, and this in turn would 

allow an obligated party to meet one of 

the nested standards, such as that for 

biomass-based diesel, using more than 

20% previous-year RINs. This could 

result in significant rollover of RINs 

with a D code of 2, representing 

biomass-based diesel, and the valid life 

of these RINs would have no meaning 

in this case. 

Some obligated parties have suggested 

that the rollover cap should be raised to 

a value higher than 20%, citing the need 

for greater flexibility in the face of 

significantly higher volume 

requirements. However, we believe that 

a higher value could create disruptions 

in the RIN market as parties with excess 

RINs would have a greater incentive to 

hold onto them rather than sell them. 

This would especially be a concern in 

years where the volume of renewable 

fuel available in the market is very close 

to the RFS requirements. Nevertheless, 

we request comment on whether the 

20% rollover cap should be raised to a 

higher value. 

As described in Section III.G.4, some 

parties have also suggested that the 

rollover cap should be lowered to a 

value lower than 20%, such as 10%. In 

the event of concerns about the 

availability of RINs, a lower rollover cap 

would provide a greater incentive for 

parties with excess RINs to sell them 

rather than hold onto them. However, a 

lower rollover cap would also reduce 

flexibility for many obligated parties. 

While we are not proposing it in today’s 

notice, we request comment on it. 

E. Concept for EPA Moderated 

Transaction System 

1. The Need for an EPA Moderated 

Transaction System 

In implementing RFS1, we found that 

the 38-digit standardized RINs have 

proven confusing to many parties in the 

distribution chain. Parties have made 

various errors in generating and using 

RINs. For example, we have seen errors 

wherein parties have transposed digits 

within the RIN. We have seen parties 

creating alphanumeric RINs, despite the 

fact that RINs are supposed to consist of 

all numbers. We have also seen 

incorrect numbering of volume start and 

end codes. 

Once an error is made within a RIN, 

the error propagates throughout the 

distribution system. Correcting an error 

can require significant time and 

resources and involve many steps. Not 

only must reports to EPA be corrected, 

underlying records and reports 

reflecting RIN transactions must also be 

located and corrected to reflect 

discovery of an error. Because reporting 

related to RIN transactions under RFS1 

is only on a quarterly basis, a RIN error 

may exist for several months before 

being discovered. 

Incorrect RINs are invalid RINs. If 

parties in the distribution system cannot 

track down and correct the error made 

by one of them in a timely manner, then 

all downstream parties that trade the 

invalid RIN will be in violation. Because 

RINs are the basic unit of compliance 

for the RFS1 program, it is important 

that parties have confidence when 

generating and using them. 

All parties in the RFS1 and the 

proposed RFS2 regulated community 

use RINs. These parties include 

producers of renewable fuels, obligated 

parties, exporters, and other owners of 

RINS, typically marketers of renewable 

fuels and blenders. (Anyone can own 

RINs, but those who do would be 

subject to registration, recordkeeping, 

reporting, and attest engagement 

requirements described in this 

preamble.). Currently under RFS1, all 

RINs are used to comply with a single 

standard, and in 2013 an additional 

cellulosic standard would have been 

added. Under this proposed rule, there 

are four standards, and RINs must be 

generated to identify four types of 

renewable fuels: cellulosic biofuel, 

biomass-based diesel, other advanced 

biofuels, and other renewable fuels (e.g., 

corn ethanol). (For a more detailed 

discussion of RINs, see Section III.A of 

this preamble.) In the proposed EPA 

Moderated Transaction System (EMTS), 

the four types of RINs will be managed 

through four types of account. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24975 

Based upon problems we observed 

with the use of RINs under RFS1, and 

considering that we will now have a 

more complex system including four 

standards instead of just one, we believe 

that the best way to screen RINs and 

conduct RIN-based transactions is 

through EMTS. 

This section describes the proposed 

EMTS and options for implementing it. 

By implementing EMTS, we believe that 

we would be able to greatly reduce RINrelated errors and efficiently and 

accurately manage the universe of RINs. 

There are two aspects to our proposal 

for EMTS. The first aspect focuses upon 

creating four, generic types of RIN 

account. The second aspect focuses 

upon actually developing a ‘‘real time’’ 

environment for handling RIN trades. 

2. How EMTS Would Work 

EMTS would be a closed, EPAmanaged system that provides a 

mechanism for screening RINs as well 

as a structured environment for 

conducting RIN transactions. 

‘‘Screening’’ RINs will mean that parties 

would have much greater confidence 

that the RINs they handle are genuine. 

Although screening cannot remove all 

human error, we believe it can remove 

most of it. 

We propose that screening and 

assignment of RINs be made at the 

logical point, i.e., the point when RINs 

are generated through production or 

importation of renewable fuel. A 

renewable producer would 

electronically submit, in ‘‘real time,’’ a 

batch report for the volume of 

renewable fuel produced or imported, as 

well as a list of the RINs generated and 

assigned. EMTS would automatically 

screen each batch and either reject the 

RINs or permit them to pass into the 

transaction system, into the RIN 

generator’s account, as one of the four 

types of RINs. Note that under RFS1, 

RIN generation (batch) and RIN 

transaction reports are submitted 

quarterly. Batch reports are submitted 

by producers and importers quarterly 

and reflect how they generated and 

assigned RINS to batches. RIN 

transaction reports are submitted by all 

parties who engage in RIN transactions, 

including buying or selling RINs. Under 

this proposed approach for RFS2, these 

batch reports and RIN transaction 

reports would be submitted monthly for 

calendar year 2010. However, once 

EMTS is implemented in calendar year 

2011, these separate periodic reports 

may no longer be necessary. Instead the 

information would be submitted as RINs 

are generated and assigned within 

EMTS. 

Under RFS1, the producer or importer 

list RINs they generate and assign via 

the batch report. EPA, in turn, uses the 

batch report data to verify RINs 

generated and transacted. The report is 

submitted quarterly. Under RFS1, the 

purpose of the RIN transaction report is 

to document RIN transactions and to 

document that RINs have been sold or 

transferred from party to party in the 

distribution system. This report is also 

submitted quarterly. The RIN 

transaction report includes the 

following information in this report: its 

name, its EPA company registration 

number, and in some cases (where 

compliance is on a facility basis), its 

EPA facility identification number. For 

the quarterly reporting period, the 

reporting party indicates the transaction 

type (RIN purchase, RIN sale, expired 

RIN, or retired RIN), and the date of the 

transaction. For a RIN purchase or sale, 

the transaction report includes the 

trading partner’s name and the trading 

partner’s EPA company registration 

number. There is also information that 

may have to be submitted in the event 

a reporting party must report a RIN that 

has been retired (e.g., when a RIN has 

become invalid due to the spillage of the 

associated volume of renewable fuel). 

As discussed above, the shortcoming of 

these reports is that they are only 

submitted quarterly. RIN errors that 

affect compliance may not be 

discovered for many months because of 

the relative infrequency of reporting 

transactions to EPA. EMTS will assume 

the functionality of batch reporting and 

transaction reporting used by regulated 

parties, allowing EPA to better screen 

RINs and reduce or eliminate generation 

and transaction errors. 

Under the RFS2 program, we are 

proposing that batch reports submitted 

by producers and importers and RIN 

transaction reports be submitted 

monthly rather than quarterly in the 

first year of the program (i.e., calendar 

year 2010). During 2010, we will be 

finishing development and testing of the 

EMTS. In order to minimize the 

hardship that undiscovered, invalid 

RINs may cause, we propose and seek 

comment on increasing the frequency of 

reporting and our own review of reports 

in order to assist the regulated 

community with compliance. As we 

develop EMTS through calendar year 

2010, we intend to invite and encourage 

interested reporting parties to ‘‘opt in’’ 

to EMTS. This will serve a two-fold 

purpose: regulated parties may opt to 

gain familiarity EMTS before it becomes 

fully operational and we may have 

actual customers with which to test 

EMTS prior to it becoming fully 

operational. We believe that permitting 

interested parties to ‘‘opt in’’ will result 

in a better EMTS for all. 

In the second year of the program (i.e., 

calendar year 2011 and forward), we 

anticipate fully implementing the 

proposed EMTS and receiving the data 

contained in batch and RIN transaction 

reports in relatively ‘‘real time’’ (i.e., as 

transactions occur). We propose that 

‘‘real time’’ be construed as within three 

(3) business days of a reportable event 

(e.g., generation and assignment of RINs, 

transfer of RINs). 

Parties who use EMTS would have to 

register with EPA in accordance with 

the proposed RFS2 registration program 

described in Section III.C of this 

preamble. They would also have to 

create an account (i.e., register) via 

EPA’s Central Data Exchange (CDX), as 

we envision managing EMTS via CDX. 

CDX is a secure and central portal 

through which parties may submit 

compliance reports. We propose that 

parties must establish an account with 

EMTS by October 1, 2010 or 60 days 

prior to engaging in any transaction 

involving RINs, whichever is later. As 

discussed above, the actual items of 

information covered by reporting under 

RFS2 are nearly identical to those 

reported under RFS1. 

Once registration occurs with EMTS, 

individual RIN accounts would be 

established and the system would 

manage the accounts for each individual 

party. The RIN accounts would 

correspond to the four broad types of 

renewable fuel. RIN accounts would be 

established for cellulosic biofuel, 

biomass-based diesel, other advanced 

biofuels, and other renewable fuels 

(including corn ethanol). One big 

advantage of RIN accounts is that the 

system would make available generic 

accounts for transactions involving RINs 

of similar type. The unique 

identification of the RIN would exist 

within EMTS, but parties engaging in 

RIN transactions would no longer have 

to worry about incorrectly recording or 

using 38-digit RIN numbers. As with 

RFS1, there is no ‘‘good faith’’ provision 

to RIN ownership. An underlying 

principle of RIN ownership is still one 

of ‘‘buyer beware’’ and RINs may be 

prohibited from use at any time if they 

are found to be invalid. Because of the 

‘‘buyer beware’’ aspect, we intend to 

offer the option for a buyer to accept or 

reject RINs from specific RIN generators 

or from classes of RIN generators. Also, 

we propose to collect information about 

the price associated with RINs traded. 

This information is not collected under 

RFS1, but we believe this information 

has great programmatic value to EPA 

because it may help us to anticipate and 

24976 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

appropriately react to market 

disruptions and other compliance 

challenges, assess and develop 

responses to potential waivers, and 

assist in setting future renewable 

standards. We believe that highly 

summarized price information (e.g., the 

average price of RINs traded 

nationwide) may be valuable to 

regulated parties, as well, and may help 

them to anticipate and avoid market 

disruptions. 

The following is an example of how 

a RIN transaction might occur in the 

proposed EMTS model: 

1. Seller logs into EMTS and posts his 

sale of 10,000 RINs to Buyer. For this 

example, assume the RINs were 

generated in 2008 and were assigned to 

10,000 gallons of ‘‘other renewable fuel’’ 

(corn ethanol). Seller’s RIN account for 

‘‘other renewable fuel’’ is automatically 

reduced by 10,000 with the posting of 

his sale to Buyer. Buyer receives 

automatic notification of the pending 

transaction. 

2. Buyer logs into EMTS. She sees the 

sale transaction pending. Assuming it is 

correct, she accepts it. Upon her 

acceptance, her RIN account for ‘‘other 

renewable fuel’’ (corn ethanol) is 

automatically increased by 10,000 2008 

assigned RINs. 

3. After Seller has posted his sale and 

Buyer has accepted it, EMTS 

automatically notifies both Buyer and 

Seller that the transaction has been fully 

completed. 

Under EMTS as we are proposing it, 

the seller would always have to initiate 

any transaction. The seller’s account is 

reduced when he posts his sale. The 

buyer must acknowledge the sale in 

order to have the RINs transferred to her 

account. Transactions would always be 

limited to available RINs. Notification 

would automatically be sent to both the 

buyer and the seller upon completion of 

the transaction. EPA proposes to 

consider any sale or transfer as complete 

upon acknowledgement by the buyer. 

We propose that RINs and the 

parameters of RIN generation (e.g., year) 

be considered public information. We 

also propose that summary RIN price 

information, such as average price of all 

RINs in a broad geographic area (such as 

a state, region, or nationwide) be 

considered public information. This 

summary price information would be 

aggregated from transactions conducted 

within EMTS, but would not be 

identified with individual companies or 

particular transactions that have 

occurred. Because we believe 

information about RIN pricing in 

general will be useful to regulated 

parties, we are proposing to make this 

information available to them. We 

propose that the actual transactions 

between parties and that individual 

company account information may be 

claimed as confidential business 

information (CBI) by the parties to that 

transaction. EPA would treat any 

information submitted that is covered 

by a CBI claim in accordance with the 

procedures at 40 CFR Part 2 and 

applicable Agency policies and 

guidelines for the handling of claimed 

CBI. 

3. Implementation of EMTS 

We anticipate that implementing 

EMTS will take until January 1, 2011, 

although we are proposing that the 

RFS2 program be effective on January 1, 

2010. We anticipate that development of 

EMTS will require significant time and 

effort and that a delayed effective date 

may permit better pre-testing with 

interested regulated parties. We propose 

to permit regulated parties who are 

willing to participate in EMTS early to 

voluntarily opt-in to the system before 

January 1, 2011. The actual date for 

these parties’ opt-in will depend upon 

the actual timeline for development of 

EMTS. We encourage comments from 

interested parties as to how we might 

best make use of the development 

period and the proposed opportunity for 

willing and interested parties to ‘‘opt 

in’’ early. 

Under our proposed scenario, for the 

2010 compliance year, recordkeeping 

and reporting would be analogous to 

RFS1, although registration would be 

enhanced in accordance with the 

discussion in Section III.C of this 

preamble and recordkeeping and 

reporting would reflect the four types of 

RIN described above. In order to avoid 

propagation of RIN-related errors and to 

prevent errors from going too long 

without being detected, we believe it is 

necessary to increase the frequency of 

batch reporting and RIN transaction 

reporting to monthly rather than 

quarterly during 2010. 

EPA will implement the EMTS during 

the first year of the RFS2 program. RINs 

generated under the RFS1 regulations 

will continue to be traded and reported 

using the current processes. RINs would 

still have unique identifying 

information, but EMTS will allow 

transactions to take place on a generic 

basis having the system track the 

specific unique identifiers. We believe 

that EMTS will virtually eliminate 

errors related to tracking and using 

individual RINs. Parties will be required 

to submit RIN transactions by specifying 

RIN year, RIN assignment, RIN fuel 

type, and any other reporting 

requirement specified by the 

administrator. 

Implementation of EMTS should save 

considerable time and resources for both 

industry and EPA. This is most evident 

considering that the proposed system 

virtually eliminates multiple sources of 

administrative errors, resulting in a 

reduction in costs and effort expended 

to correct and regenerate product 

transfer documents, documentation and 

recordkeeping, and resubmitting reports 

to EPA. We anticipate that a fully 

functioning EMTS will result in fewer 

reports and easier reporting for industry, 

and fewer reports requiring processing 

by EPA. Industry will need to spend less 

time and effort verifying the validity of 

the RINs they procure and allowing 

them to procure them on the open 

market with confidence. EPA will need 

to spend less time tracking down the 

responsible parties for invalid RINs. 

This is possible because EMTS will 

remove management of the 38-digit RIN 

from the hands of the reporting 

community. At the same time, EPA and 

the reporting community will be 

working with a standardized system, 

reducing stresses and development costs 

on IT systems. 

In summary, the advantage to 

implementing EMTS is that parties may 

engage in RIN transactions with a high 

degree of confidence. Errors would be 

virtually eliminated. Everyone engaging 

in RIN transactions would have a 

simplified environment in which to 

work which should minimize the level 

of resources needed for implementation. 

However, the one unavoidable 

disadvantage that we foresee is that 

parties would have to switch to a new 

and different reporting system in the 

second year of the RFS2 program. Some 

errors may still occur in by parties who 

continue to generate and use the 38- 

digit RINs during 2010. As discussed 

above, we propose to increase the 

frequency of batch and RIN transaction 

reporting to monthly for 2010, in order 

that we may help parties discover errors 

and correct them before they become 

violations. We also propose to permit 

parties to voluntarily ‘‘opt in’’ to using 

EMTS while it is still in development in 

order to ease the transition. We invite 

comment from all interested parties as 

to how we may best assist regulated 

parties in transitioning from the ‘‘old’’ 

RFS1 method of handing RINs to the 

‘‘new,’’ proposed RFS2 EMTS method 

on January 1, 2011. 

We also invite comment on whether, 

in the event the RFS2 start date is 

delayed, EPA should nevertheless allow 

a one-year period during which use of 

EMTS is optional, or if EPA should 

begin the program at the inception of 

the delayed RFS2 program if EMTS is 

fully operational at that time. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24977 

45See section 80.1469 in the proposed regulatory 

text. 

46An E85 nozzle design and corresponding flexfuel vehicle filler design that would prevent the 

introduction of E85 into non-flex-fuel vehicles 

while allowing flex fuel vehicles to be fueled with 

E10 as well as E85 would also prevent the 

introduction of E85 into current flex-fuel vehicles 

since there is currently no difference in nozzle/filler 

neck hardware between flex-fuel and non-flex-fuel 

vehicles. 

47EIA. Annual Energy Outlook 2007 with 

Projections to 2030. http://www.eia.doe.gov/oiaf/ 

archive/aeo07/index.html. Accessed February 2008. 

F. Retail Dispenser Labelling for 

Gasoline With Greater Than 10 Percent 

Ethanol 

Fuel retailers expressed concern that 

the magnitude of the price discount for 

E85 relative to E10 that would be 

necessary to facilitate sufficient use of 

E85 would encourage widespread 

misfueling of non-flex fuel vehicles. 

Today’s proposal contains labeling 

requirements for pumps that dispense 

blends that contain greater than 10% 

ethanol which state that the use in nonflex fuel vehicles is prohibited and may 

cause damage to the vehicle.45 We 

anticipate that the industry would also 

conduct public information activities to 

alert customers who may not have yet 

become accustomed to seeing E85 at 

retail to avoid using E85 in their nonflex-fuel vehicles. Uniquely colored/ 

labeled nozzle handles may also be 

useful in helping to prevent accidental 

cases of misfueling. We believe that in 

most cases the warnings that the use of 

E85 in non-flex fuel vehicles is illegal, 

can damage the vehicle, and can void 

vehicle manufacturer warranties may be 

a sufficient disincentive to prevent 

intentional misfueling. In cases where 

intentional misfueling may occasionally 

take place, the party is likely to 

experience drivability problems and 

thus would not repeat the act. 

Today’s proposal does not contain 

requirements that E85 refueling 

hardware be configured to prevent the 

introduction of E85 into non-flex-fuel 

vehicles. It is unclear how such an 

approach could be implemented to 

allow the approximately 6 million flexfuel vehicles on the road today to 

continue to be fueled with E85 without 

modification to their filler neck 

hardware.46 In any event, we do not 

believe that unique E85 nozzles are 

necessary. 

We request comment on whether the 

proposed labeling requirements and 

voluntary measures such as those 

described above would provide 

sufficient warning to fuel retail 

customers not to refuel non-flex-fuel 

vehicles with E85. To the extent that 

other measures to prevent misfueling 

are thought to be necessary, comment is 

requested on the specific nature of such 

measures and the associated potential 

costs and benefits. One additional 

potential measure to prevent misfueling 

would be for cards to be issued to flex 

fuel vehicle owners and for all E85 

dispensers to be equipped with card 

readers that would allow E85 to be 

dispensed only to card holders. 

V. Assessment of Renewable Fuel 

Production Capacity and Use 

To assess the impacts of this rule, 

there must be a clear understanding of 

the kind of renewable fuels that could 

be used, the types and locations of their 

feedstocks, the fuel volumes that could 

be produced by a given feedstock, and 

any challenges associated with their 

use. This section provides this 

assessment of the potential feedstocks 

and renewable fuels that may be used to 

meet the Energy Independence and 

Security Act (EISA) and the rationale 

behind our projections of various fuel 

types to represent the control case for 

analysis purposes. Definitional issues 

regarding the four types of renewable 

fuel required under EISA are discussed 

in Section III.B of this preamble. 

A. Summary of Projected Volumes 

EISA mandates the use of increasing 

volumes of renewable fuel. To assess the 

impacts of this increase in renewable 

fuel volume from business-as-usual 

(what is likely to have occurred without 

EISA), we have established a reference 

and control case from which subsequent 

analyses are based. The reference case is 

essentially a projection of renewable 

fuel volumes without the enactment of 

EISA. The control case is a projection of 

the volumes and types of renewable fuel 

that might be used to comply with the 

EISA volume mandates. Both the 

reference and control cases are 

discussed in further detail below. 

1. Reference Case 

Our reference case renewable fuel 

volumes are based on the Energy 

Information Administration’s (EIA) 

Annual Energy Outlook (AEO) 2007 

reference case projections. The AEO 

2007 presents long-term projections of 

energy supply, demand, and prices 

through 2030 based on results from 

EIA’s National Energy Modeling System 

(NEMS). EIA’s analysis focuses 

primarily on a reference case (which we 

use as our reference case), lower and 

higher economic growth cases, and 

lower and higher energy price cases. 

AEO 2007 projections generally are 

based on Federal, State, and local laws 

and regulations in effect on or before 

October 31, 2006.47 The potential 

impacts of pending or proposed 

legislation, regulations, and standards 

are not reflected in the projections. 

While AEO 2007 is not as up-to-date as 

AEO 2008 (or the recently released AEO 

2009), we chose to use AEO 2007 

because AEO 2008 already includes the 

impact of increased renewable fuel 

volumes under EISA as well as fuel 

economy improvements under CAFE, 

whereas AEO 2007 did not. Table 

V.A.1–1 summarizes the fuel types and 

volumes for the years 2009–2022 as 

taken from AEO 2007. For our air 

quality analysis we also considered a 

reference case assuming the mandated 

renewable fuel volumes under the 

Renewable Fuel Standard Program from 

the Energy Policy Act of 2005 (EPAct). 

Refer to Section VII for further details. 

TABLE V.A.1–1—AEO 2007 REFERENCE CASE PROJECTED RENEWABLE FUEL VOLUMES

[billion gallons] 

Year 

Advanced biofuel Non-advanced 

biofuel 

Total 

renewable 

fuel 

Cellulosic 

biofuel 

Biomassbased diesela

Other advanced biofuel 

Corn 

Cellulosic ethanol 

ethanol 

FAME 

biodieselb

Imported 

ethanol 

2009 ..................................................................................... 0.07 0.32 0.50 9.44 10.33 

2010 ..................................................................................... 0.12 0.32 0.29 10.49 11.22 

2011 ..................................................................................... 0.19 0.33 0.16 10.69 11.37 

2012 ..................................................................................... 0.25 0.33 0.18 10.81 11.57 

24978 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

TABLE V.A.1–1—AEO 2007 REFERENCE CASE PROJECTED RENEWABLE FUEL VOLUMES—Continued 

[billion gallons] 

Year 

Advanced biofuel Non-advanced 

biofuel 

Total 

renewable 

fuel 

Cellulosic 

biofuel 

Biomassbased diesela

Other advanced biofuel 

Corn 

Cellulosic ethanol 

ethanol 

FAME 

biodieselb

Imported 

ethanol 

2013 ..................................................................................... 0.25 0.33 0.19 10.93 11.70 

2014 ..................................................................................... 0.25 0.23 0.20 11.01 11.69 

2015 ..................................................................................... 0.25 0.25 0.39 11.10 11.99 

2016 ..................................................................................... 0.25 0.35 0.51 11.16 12.27 

2017 ..................................................................................... 0.25 0.36 0.53 11.30 12.44 

2018 ..................................................................................... 0.25 0.36 0.54 11.49 12.64 

2019 ..................................................................................... 0.25 0.37 0.58 11.69 12.89 

2020 ..................................................................................... 0.25 0.37 0.60 11.83 13.05 

2021 ..................................................................................... 0.25 0.38 0.63 12.07 13.33 

2022 ..................................................................................... 0.25 0.38 0.64 12.29 13.56 

aBiomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. AEO 2007 only projects FAME 

biodiesel volumes. bFatty acid methyl ester (FAME) biodiesel. 

2. Control Case for Analyses 

Our assessment of the renewable fuel 

volumes required to meet EISA 

necessitates establishing a primary set of 

fuel types and volumes on which to 

base our assessment of the impacts of 

the new standards. EISA contains four 

broad categories: cellulosic biofuel, 

biomass-based diesel, total advanced 

biofuel, and total renewable fuel. As 

these categories could be met with a 

wide variety of fuel choices, in order to 

assess the impacts of the rule, we 

projected a set of reasonable renewable 

fuel volumes based on our 

interpretation at the time we began our 

analysis of likely fuels that could come 

to market. 

Although actual volumes and 

feedstocks may be different, we believe 

the projections made for our control 

case are within the range of reasonable 

predictions and allow for an assessment 

of the potential impacts of the RFS2 

standards. Table V.A.2–1 summarizes 

the fuel types used for the control case 

and their corresponding volumes for the 

years 2009–2022. 

TABLE V.A. 2–1—CONTROL CASE PROJECTED RENEWABLE FUEL VOLUMES

[billion gallons] 

Year 

Advanced biofuel Non-Advanced 

Biofuel 

Total renewable fuel 

Cellulosic 

biofuel 

Biomass-based diesel a Other advanced biofuel 

Corn 

Cellulosic ethanol 

ethanol 

FAMEb

biodiesel 

Non-coprocessed 

renewable 

diesel 

Co-processed renewable 

diesel 

Imported 

ethanol 

2009 ......................................................... 0.00 0.50 0.00 0.00 0.50 9.85 10.85 

2010 ......................................................... 0.10 0.64 0.01 0.01 0.29 11.55 12.60 

2011 ......................................................... 0.25 0.77 0.03 0.03 0.16 12.29 13.53 

2012 ......................................................... 0.50 0.96 0.04 0.04 0.18 12.94 14.66 

2013 ......................................................... 1.00 0.94 0.06 0.06 0.19 13.75 16.00 

2014 ......................................................... 1.75 0.93 0.07 0.07 0.36 14.40 17.58 

2015 ......................................................... 3.00 0.91 0.09 0.09 0.83 15.00 19.92 

2016 ......................................................... 4.25 0.90 0.10 0.10 1.31 15.00 21.66 

2017 ......................................................... 5.50 0.88 0.12 0.12 1.78 15.00 23.40 

2018 ......................................................... 7.00 0.87 0.13 0.13 2.25 15.00 25.38 

2019 ......................................................... 8.50 0.85 0.15 0.15 2.72 15.00 27.37 

2020 ......................................................... 10.50 0.84 0.16 0.16 2.70 15.00 29.36 

2021 ......................................................... 13.50 0.83 0.17 0.17 2.67 15.00 32.34 

2022 ......................................................... 16.00 0.81 0.19 0.19 3.14 15.00 35.33 

aBiomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. 

bFatty acid methyl ester (FAME) biodiesel. 

We needed to make this projection 

soon after EISA was signed to allow 

sufficient time to conduct our long leadtime analyses. As a result, we used the 

same ethanol-equivalence basis for these 

projections as was used in the RFS1 

rulemaking. However, as described in 

Section III.D.1, we are also co-proposing 

that volumes of renewable fuel be 

counted on a straight gallon-for-gallon 

basis under RFS2, such that all 

Equivalence Values would be 1.0. The 

net effect of these two approaches to 

Equivalence Values on projected 

volumes is very small; instead of 36 

billion gallons of renewable fuel in 

2022, our control case includes 35.3 

billion gallons. We do not believe that 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24979 

48This is currently an area of intense research. 

this difference will substantively affect 

the analyses that are based on our 

projected control case volumes. 

The following subsections detail our 

rationale for projecting the amount and 

type of fuels needed to meet EISA as 

shown in Table V.A.2–1. For cellulosic 

biofuel we have assumed that the entire 

volume will be domestically produced 

cellulosic ethanol. Biomass-based diesel 

is assumed to be comprised of a 

majority of fatty-acid methyl ester 

(FAME) biodiesel and a smaller portion 

of non-co-processed renewable diesel. 

The portion of the advanced biofuel 

category not met from cellulosic biofuel 

and biomass-based diesel is assumed to 

come mainly from imported (sugarcane) 

ethanol with a smaller amount from coprocessed renewable diesel. The total 

renewable fuel volume not required to 

be comprised of advanced biofuels is 

assumed to be met with corn ethanol. 

In addition, the following subsections 

also describe other fuels that have the 

potential to contribute to meeting EISA, 

but because of their uncertainty of use, 

or because their use likely might be 

negligible we have chosen to not assume 

any use for our analysis. Examples of 

these types of renewable fuels or 

blendstocks include bio-butanol, biogas, 

cellulosic diesel, cellulosic gasoline, 

biofuel from algae, jatropha, or palm, 

imported cellulosic ethanol, other 

biomass-to-liquids (BTL), and other 

alcohols or ethers. We intend to revisit 

these assumptions for the final rule and 

invite comment on whether these 

renewable fuels or other potential fuels 

which have not been included in our 

analyses should be included. 

a. Cellulosic Biofuel 

As defined in EISA, cellulosic biofuel 

means renewable fuel produced from 

any cellulose, hemicellulose, or lignin 

that is derived from renewable biomass 

and that has lifecycle greenhouse gas 

emissions, as determined by the 

Administrator, that are at least 60% less 

than the baseline lifecycle greenhouse 

gas emissions. 

When many people think of cellulosic 

biofuel, they immediately think of 

cellulosic ethanol. However, cellulosic 

biofuel could be comprised of other 

alcohols, synthetic gasoline, synthetic 

diesel fuel, and synthetic jet fuel, 

propane, and biogas. Whether cellulosic 

biofuel is ethanol will depend on a 

number of factors, including production 

costs, the form of tax subsidies, credit 

programs, and issues associated with 

blending the biofuel into the fuel pool. 

It will also depend on the relative 

demand for gasoline and diesel fuel. For 

instance, European refineries are 

undersupplying the European market 

with diesel fuel and oversupplying it 

with gasoline, and based on the recent 

high diesel fuel price margins over 

gasoline, it seems that the U.S. is falling 

in line with Europe. Therefore, if the 

U.S. trend is toward being relatively 

oversupplied with gasoline, there could 

be a price advantage towards producing 

renewable fuels that displace diesel fuel 

rather than a gasoline fuel replacement 

like ethanol. 

Current efforts in converting 

cellulosic feedstocks into fuels focus on 

biochemical and thermochemical 

conversion processes. Biochemical 

processes use live bacteria or isolated 

enzymes, or acids, to break cellulose 

down into fermentable sugars. The 

advantage of using live bacteria or 

enzymes is that simple carbon steel 

could be used which helps to control 

the capital costs. However, bacteria and 

enzymes that break down cellulose are 

generally specific to certain types of 

cellulose, thus, the cellulosic biofuel 

facility may have difficulty processing 

different types of feedstocks.48 If live 

bacteria are used, the bacteria could be 

susceptible to contamination that could 

force a plant shutdown. An example of 

a company using enzymes to process 

cellulose into ethanol is Iogen, which 

has a demonstration plant in Canada. 

On the other hand, biochemical 

processes which rely on strong acids 

will likely be less susceptible to 

contamination issues, and could more 

easily process mixed feedstocks. Thus, 

strong acid biochemical cellulosic 

ethanol plants could process MSW or a 

variety of feedstocks which may be 

available in areas where no single 

feedstock dominates. The strong acids, 

however, would likely require more 

expensive metallurgy. A company 

which is planning to use strong acids to 

hydrolyze the cellulose is Blue Fire 

Ethanol. Blue Fire is planning on 

building a MSW plant in Southern 

California. Once cellulose is reduced to 

simple sugars, either strong acid or 

enzymatic cellulosic ethanol plants 

operate in a manner similar to a corn 

ethanol plant. This consists of 

fermenting sugars into ethanol and then 

separating the ethanol from the water 

that facilitated the fermentation step. 

The thermochemical conversion 

process is very different from the 

biochemical process right from the 

beginning. For the thermochemical 

process, feedstocks are partially burned 

with oxygen at a very high temperature 

and converted into a synthesis gas 

comprised of carbon monoxide and 

hydrogen. The principal advantage of 

the thermochemical process is that 

virtually any hydrocarbon material 

could be processed as feedstock, as they 

would all be converted to the synthesis 

gas, even if they produce different 

relative concentrations of carbon 

monoxide and hydrogen. The synthesis 

gas is typically converted to ethanol or 

diesel by one of several different 

processes. 

Examples of companies currently 

pursuing the thermochemical route to 

selectively produce ethanol include 

Range Ethanol and Coskata. Range 

Ethanol is using a specially formulated 

catalyst that will primarily produce 

ethanol, but it will produce other higher 

molecular weight alcohols as well 

which would be recycled and mostly 

converted to ethanol. Coskata, which is 

being supported by General Motors, is 

planning on using bacteria to convert 

the synthesis gas to ethanol. 

Another thermochemical plant could 

employ a very similar gasification 

reactor, but instead of producing 

ethanol from syngas, a Fischer Tropsch 

(F–T) reactor would be used to produce 

a primarily diesel product, i.e., 

cellulosic diesel. The F–T reactor would 

use a specially designed iron or cobalt 

catalyst to convert the syngas to straight 

chain hydrocarbon compounds of 

varying lengths and molecular weights. 

The heavier of these hydrocarbon 

compounds are then hydrocracked to 

produce a very high percentage of 

valuable diesel fuel and naphtha 

(gasoline type compounds). The F–T 

diesel fuel produced from the F–T 

process is very high in quality due to its 

high cetane and essentially zero sulfur 

level. While the naphtha produced from 

the F–T process also contains 

essentially zero sulfur, it is very low in 

octane and thus is a poor gasoline 

blendstock (although it could still be 

desirable as a gasoline blendstock 

because of all the high octane ethanol 

being blended into gasoline). Cellulosic 

naphtha is also valuable as a cracking 

feedstock for producing various 

petrochemical compounds. Since the F– 

T diesel is of better quality than the 

naphtha, the heavier hydrocarbon 

compounds are selectively 

hydrocracked to produce more diesel 

over naphtha. 

No commercial cellulosic diesel 

plants currently exist in the U.S., nor 

elsewhere in the world. Currently, there 

is a cellulosic diesel pilot plant operated 

by Choren in Germany and a 

commercial sized plant in the planning 

stages by Choren also in Germany. 

Choren is planning to employ woody 

materials and agricultural residue as 

feedstocks. Choren specially developed 

a three-stage gasification process for 

dealing with the complexities of 

24980 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

49Wright, M. and Brown, R, ‘‘Comparative 

Economics of Biorefineries Based on the 

Biochemical and Thermochemical Platforms,’’ 

Biofuels, Bioprod. Bioref. 1:49–56, 2007. 

50Countries evaluated include Argentina, Brazil, 

Canada, China, Colombia, India, Mexico, and CBI. 

51 Kline, K. et al., ‘‘Biofuel Feedstock Assessment 

for Selected Countries,’’ Oak Ridge National 

Laboratory, February 2008. 

52Recent changes to federal tax subsidies and 

market shifts may warrant changes to this 

assumption. We will reevaluate the relative 

production volumes of biodiesel and renewable 

diesel for the FRM. 

53This analysis was conducted prior to the 

completion of our lifecycle analysis discussed in 

Section VI, and assumes the fuels will meet the 

required GHG threshold. 

biomass and has partnered with Shell 

which has commercialized a F–T 

reaction process. The Choren 

commercial cellulosic diesel plant in 

Germany is expected to begin operating 

in 2010. Although coal-to-liquids (CTL) 

plants rely on coal as their feedstock, 

they are very similar to cellulosic diesel 

plants in design and help to 

demonstrate the feasibility of the 

cellulosic diesel process. There are CTL 

pilot plants which are operating today, 

as well as a number of commercial CTL 

plants operating today or in the 

planning stages. Some of these plants 

have experimented with or are being 

planned for co-feeding biomass along 

with the coal. A current list of proposed 

cellulosic diesel and CTL plants is 

provided in Chapter 1 of the DRIA. 

In terms of production costs, at least 

for the current state of technology, 

neither the biochemical nor 

thermochemical platforms (comparing 

enzymatic biochemical processing to 

ethanol and thermochemical processing 

to cellulosic diesel) appear to have clear 

advantages in capital costs or operating 

costs.49 Other processing techniques, for 

example, the syngas-to-ethanol process 

used by Coskata, claim to be capable of 

producing at even lower production 

costs, but without any commercial 

facilities operating today, it is hard to 

predict how these other processing 

techniques differ from our estimates of 

what the production costs for cellulosic 

biofuel facilities will be in the future 

and which technology pathways will be 

most economic. As such, both 

enzymatic biochemical and 

thermochemical technologies could be 

key processing pathways for the 

production of cellulosic biofuel. 

The economic competitiveness of 

cellulosic biofuels will also depend on 

the extent of financial support from the 

government. Under the Farm Bill of 

2008, both cellulosic ethanol and 

cellulosic diesel receive the same tax 

subsidies ($1.01 per gallon each). The 

tax subsidy, however, gives ethanol 

producers a considerable advantage over 

those producing cellulosic diesel due to 

the feedstock quantity needed per gallon 

produced (i.e., typically the higher the 

energy content of the product, the more 

feedstock that is required). On an energy 

basis, cellulosic ethanol would receive 

approximately $13/mmBtu while 

cellulosic diesel would receive 

approximately $8/mmBtu. In a similar 

manner, if we were to finalize an 

approach to the Equivalence Values for 

generating RINs in which volume rather 

than energy content is the basis, there 

would be an advantage for the 

production of cellulosic ethanol over 

cellulosic diesel. 

One large advantage that cellulosic 

diesel has over ethanol is the ability for 

the fuel to be blended easily into the 

current distribution infrastructure at 

sizeable volumes. There are currently 

factors tending to limit the amount of 

ethanol that can be blended into the fuel 

pool (see Section V.D. for more 

discussion). Thus, the production of 

cellulosic diesel instead of cellulosic 

ethanol could help increase 

consumption of renewable fuels. 

Thus, there is uncertainty as to which 

mix of cellulosic biofuels will be 

produced to fulfill the 16 Bgal mandate 

by 2022. The latest release of AEO 2009, 

for example, estimates a mixture of 

cellulosic diesel and ethanol produced 

for cellulosic biofuel. For assessing the 

impacts of the RFS2 standards, we made 

the simplifying assumption that 

cellulosic biofuel would only consist of 

ethanol, though market realities may 

also result in cellulosic diesel and other 

products. We are requesting comment 

on the types of cellulosic biofuel that 

should be accounted for in our analyses 

and whether certain fuels are more 

likely to come to fruition than others. 

Cellulosic biofuel could also be 

produced internationally. One example 

of internationally produced cellulosic 

biofuel is ethanol produced from 

bagasse or straw from sugarcane 

processing in Brazil. Currently, Brazil 

burns bagasse to produce steam and 

generate bioelectricity. However, 

improving efficiencies over the coming 

decade may allow an increasing portion 

of bagasse to be allocated to other uses, 

including cellulosic biofuel, as the 

demand for bagasse for steam and 

bioelectricity could remain relatively 

constant. 

One recent study assessed the 

biomass feedstock potential for selected 

countries outside the United States and 

projected supply available for export or 

for biofuel production.50 51 For the 

study’s baseline projection in 2017, it 

was estimated that approximately 21 

billion ethanol-equivalent gallons could 

be produced from cellulosic feedstocks 

at $36/dry tonne or less. The majority 

(∼80%) projected is from bagasse, with 

the rest from forest products. Brazil was 

projected to have the most potential for 

cellulosic feedstock production from 

both bagasse and forest products. Other 

countries include India, China, and 

those belonging to the Caribbean Basin 

Initiative (CBI), though much smaller 

feedstock supplies are projected as 

compared to Brazil. Although 

international production of cellulosic 

biofuel is possible, it is uncertain 

whether this supply would be available 

primarily to the U.S. or whether other 

nations would consume the fuel 

domestically. Therefore, for our 

analyses we have chosen to assume that 

all the cellulosic biofuel used to comply 

with RFS2 would be produced 

domestically. 

b. Biomass-Based Diesel 

Biomass-based diesel as defined in 

EISA means renewable fuel that is 

biodiesel as defined in section 312(f) of 

the Energy Policy Act of 1992 with 

lifecycle greenhouse gas emissions, as 

determined by the Administrator, that 

are at least 50% less than the baseline 

lifecycle greenhouse gas emissions. 

Biomass-based diesel can include fatty 

acid methyl ester (FAME) biodiesel, 

renewable diesel (RD) that has not been 

co-processed with a petroleum 

feedstock, as well as cellulosic diesel. 

Although cellulosic diesel produced 

through the Fischer-Tropsch (F–T) 

process could potentially contribute to 

the biomass-based diesel category, we 

have assumed for our analyses that the 

fuel and its corresponding feedstocks 

(cellulosic biomass) are already 

accounted for in the cellulosic biofuel 

category discussed previously in 

Section V.A.2.a. 

FAME and RD processes can make 

acceptable quality fuel from vegetable 

oils, fats, and greases, and thus will 

generally compete for the same 

feedstock pool. For our analyses, we 

have assumed that the volume 

contribution from FAME biodiesel and 

RD will be a function of the available 

feedstock types. In our analysis we 

assumed that virgin plant oils would be 

preferentially processed by biodiesel 

plants, while the majority of fats and 

greases would be routed to RD 

production.52 53 This is because the RD 

process involves hydrotreating (or 

thermal depolymerization), which is 

more severe and uses multiple chemical 

mechanisms to reform the fat molecules 

into diesel range material. The FAME 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24981 

54Algenol and Sapphire Energy, see http:// 

www.algenolbiofuels.com/ and http:// 

www.sapphireenergy.com/. 

55While cellulosic biofuel will not be limited by 

feedstock availability, it likely will be limited by 

the very aggressive ramp up in production volume 

for an industry which is still being demonstrated on 

the pilot scale and therefore is not yet commercially 

viable. On the other hand, biomass-based diesel 

derived from agricultural oils and animal fats are 

faced with relatively high feedstock costs which 

limit feedstock supply. 56This analysis was conducted prior to the 

completion of our lifecycle analysis discussed in 

Section VI, and assumes the fuel will meet the 

required GHG threshold. 

57Personal communication with Nathalie 

Hoffman, Managing Member of California 

Renewable Energies, LLC, August 27, 2008. 

process, by contrast, relies on more 

specific chemical mechanisms and 

requires pre-treatment if the feedstocks 

contain more than trace amounts of free 

fatty acids or other contaminates which 

are typical of recycled fats and greases. 

In terms of volume availability of 

feedstocks, supplies of fats and greases 

are more limited than virgin vegetable 

oils. As a result, our control case 

assumes the majority of biomass-based 

diesel volume is met using biodiesel 

facilities processing vegetable oils, with 

RD making up a smaller portion and 

using solely fats and greases. 

The RD production volume must be 

further classified as co-processed or 

non-co-processed, depending on 

whether the renewable material was 

mixed with petroleum during the 

hydrotreating operations (more details 

on this definition are in Section III.B.1). 

EISA specifically forbids co-processed 

RD from being counted as biomassbased diesel, but it can still count 

toward the total advanced biofuel 

requirement. What fraction of RD will 

ultimately be co-processed is uncertain 

at this time, since little or no 

commercial production of RD is 

currently underway, and little public 

information is available about the 

comparative economics and feasibility 

of the two methods. We assumed in our 

control case that half the material will 

be non-co-processed and thus qualify as 

biomass-based diesel. We invite 

comment on whether RD production 

will favor co-processing or non-coprocessing with a petroleum feedstock 

in the future. 

Perhaps the feedstock with the 

greatest potential for providing large 

volumes of oil for the production of 

biomass-based diesel is microalgae. 

Algae grown on land in photobioreactors or in open ponds could 

potentially yield 15 to 50 times more oil 

per acre than traditional oil crops such 

as soy, rapeseed, or oil palm. 

Additionally it can be cultivated on 

marginal land with low nutrient inputs, 

and thus does not suffer from the sheer 

resource constraints that make other 

biofuel feedstocks problematic at large 

scale. However, several technical 

hurdles do still exist. Specifically, more 

efficient harvesting, dewatering and 

lipid extraction methods are needed to 

lower costs to a level competitive with 

other biodiesel feedstocks (20–30% of 

current costs). Until these hurdles are 

overcome, it is unlikely that algae-based 

biodiesel can be commercially 

competitive with other biodiesel fuels. 

Thus, for our control case we have 

chosen not to include oil from algae as 

a feedstock. Although the majority of 

algae to biofuel companies are focusing 

on producing algae oil for traditional 

biodiesel production, several companies 

are alternatively using algae for 

producing ethanol or crude oil for 

gasoline or diesel which could also help 

contribute to the advanced biofuel 

mandate.54 For more detail on algae as 

a feedstock refer to Section 1.1 of the 

DRIA. 

Jatropha curcas, a shrub native to 

Central America, is yet another possible 

biofuel feedstock. The perennial yields 

oil-rich seeds yearly, with oil yields per 

acre up to 4 times that of soy and twice 

that of rapeseed under optimal 

conditions. It can grow on low-nutrient 

lands, and is tolerant of drought. 

However, jatropha yields under these 

marginal conditions are hard to predict 

because of insufficient commercial 

experience; it is possible that jatropha 

will have low yields in the sub-optimal 

conditions where its cultivation would 

be most advantageous. Furthermore, 

jatropha seed harvesting is very labor 

intensive, and little is known about the 

crop’s sustainability impacts, its longterm yield, or the feasibility of 

cultivation as a monoculture. It is 

unlikely that jatropha can be cultivated 

in the United States economically or 

sustainably, and the possibility of 

importing jatropha oil or biodiesel from 

producing countries is very uncertain 

because overseas cultivation efforts are 

still underdeveloped and initial 

volumes will likely be used 

domestically. As a result, we have not 

projected the use of jatropha as a 

feedstock under our control case. For 

more detail on the potential use of 

jatropha refer to Section 1.1 of the DRIA. 

c. Other Advanced Biofuel 

As defined in EISA, advanced biofuel 

means renewable fuel, other than 

ethanol derived from corn starch, that 

has lifecycle greenhouse gas emissions, 

as determined by the Administrator, 

that are at least 50% less than baseline 

lifecycle greenhouse gas emissions. As 

described more fully in Section VI.D, we 

are proposing that the GHG threshold 

for advanced biofuels be adjusted to 

44% or potentially as low as 40% 

depending on the results from the 

analyses that will be conducted for the 

final rule. As defined in EISA, advanced 

biofuel includes the cellulosic biofuel, 

biomass-based diesel, and co-processed 

renewable diesel categories that were 

mentioned in Sections V.A.2.a and 

V.A.2.b above. However, EISA requires 

greater volumes of advanced biofuel 

than just the volumes required of these 

fuels; see Table V.A.2–1. It is entirely 

possible that greater volumes of 

cellulosic biofuel, biomass-based diesel, 

and co-processed renewable diesel than 

required by EISA could be produced in 

the future. Our control case, however, 

does not assume that cellulosic biofuel 

and biomass-based diesel volumes will 

exceed those required under EISA.55 As 

a result, to meet the total advanced 

biofuel volume required under EISA, 

advanced biofuel types are needed other 

than cellulosic biofuel, biomass-based 

diesel, and co-processed renewable 

diesel through 2022. 

We have assumed for our control case 

that the most likely source of advanced 

fuel other than cellulosic biofuel, 

biomass-based diesel, and co-processed 

renewable diesel would be from 

imported sugarcane ethanol.56 Our 

assessment of international fuel ethanol 

production and demand indicate that 

anywhere from 3.8–4.2 Bgal of 

sugarcane ethanol from Brazil could be 

available for export by 2020/2022. If this 

volume were to be made available to the 

U.S., then there would be sufficient 

volume to meet the advanced biofuel 

standard. To calculate the amount of 

imported ethanol needed to meet the 

EISA standards, we took the difference 

between the total advanced biofuel 

category and cellulosic biofuel, biomassbased diesel, and co-processed 

renewable diesel categories. The amount 

of imported ethanol required by 2022 is 

approximately 3.2 Bgal. We solicit 

comment on our estimate of 3.2 Bgal 

and whether or not it is reasonable to 

assume that Brazil (or any other 

country) could satisfy this demand. 

Recent news indicates that there are 

also plans for sugarcane ethanol to be 

produced in the U.S in places where the 

sugar subsidy does not apply. For 

instance, sugarcane has been grown in 

California’s Imperial Valley specifically 

for the purpose of making ethanol and 

using the cane’s biomass to generate 

electricity to power the ethanol 

distillery as well as export excess 

electricity to the electric grid.57 There 

are at least two projects being developed 

at this time that could result in several 

24982 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

58To obtain EPA approval for butanol blends as 

high as 16% by volume would require that the 

butanol be blended with an approved corrosion 

inhibitor. 

59National Renewable Energy Laboratory 

estimate based on biomass portion available at $45– 

$55/dry ton. Using POLYSYS Policy Analysis 

System, Agricultural Policy Analysis Center, 

University of Tennessee. http://www.agpolicy.org/ 

polysys.html. Accessed May 2008. 

60Milbrandt, A., ‘‘Geographic Perspective on the 

Current Biomass Resource Availability in the 

United States.’’ 70 pp., NREL Report No. TP–560– 

39181, 2005. 

hundred million gallons of ethanol 

produced. The sugarcane is being grown 

on marginal and existing cropland that 

is unsuitable for food crops and will 

replace forage crops like alfalfa, 

Bermuda grass, Klein grass, etc. 

Harvesting is expected to be fully 

mechanized. Thus, there is potential for 

these projects and perhaps others to 

help contribute to the EISA biofuels 

mandate. This could lower the volume 

needed to be imported from Brazil. 

Butanol is another potential motor 

vehicle fuel which could be produced 

from biomass and used in lieu of 

ethanol to comply with the RFS2 

standard. Production of butanol is being 

pursued by a number of companies 

including a partnership between BP and 

Dupont. Other companies which have 

expressed the intent to produce 

biobutanol are Baer Biofuels and Gevo. 

The near term technology being pursued 

for producing butanol involves 

fermentation of starch compounds, 

although it can also be produced from 

cellulose. Butanol has several inherent 

advantages compared to ethanol. First, it 

has higher energy density than ethanol 

which would improve fuel economy 

(mpg). Second, butanol is much less 

water soluble which may allow the 

butanol to be blended in at the refinery 

and the resulting butanol-gasoline blend 

then more easily shipped through 

pipelines. This would reduce 

distribution costs associated with 

ethanol’s need to be shipped separately 

from its gasoline blendstock and also 

save on the blending costs incurred at 

the terminal. Third, butanol can be 

blended in higher concentrations than 

10% which would likely allow butanol 

to be blended with gasoline at high 

enough concentrations to avoid the need 

for most or all of high concentration 

ethanol-gasoline blends, such as E85, 

that require the use of fuel flexible 

vehicles. For example, because of 

butanol’s lower oxygen content, it can 

be blended at 16% (by volume) to match 

the oxygen concentration of ethanol 

blended at 10% (by volume).58 Because 

of butanol’s higher energy density, 

when blending butanol at 16% by 

volume, it is the renewable fuels 

equivalent to blending ethanol at about 

20 percent. Thus, butanol would enable 

achieving most of the RFS2 standard by 

blending a lower concentration of 

renewable fuel than having to resort to 

a sizable volume of E85 as in the case 

of ethanol. As pointed out in Section 

V.D., the need to blend ethanol as E85 

provides some difficult challenges. The 

use of butanol may be one means of 

avoiding these blending difficulties. 

At the same time, butanol has a 

couple of less desirable aspects relative 

to ethanol. First, butanol is lower in 

octane compared to ethanol—ethanol 

has a very high blending octane of 

around 115, while butanol’s octane 

ranges from 87 octane numbers for 

normal butanol and 94 octane numbers 

for isobutanol. Potential butanol 

producers are likely to pursue 

producing isobutanol over normal 

butanol because of isobutanol’s higher 

octane content. Higher octane is a 

valuable attribute of any gasoline 

blendstock because it helps to reduce 

refining costs. A second negative 

property of butanol is that it has a much 

higher viscosity compared to either 

gasoline or ethanol. High viscosity 

makes a fuel harder to pump, and more 

difficult to atomize in the combustion 

chamber in an internal combustion 

engine. The third downside to butanol 

is that it is more expensive to produce 

than ethanol, although the higher 

production cost is partially offset by its 

higher energy density. 

Another potential source of renewable 

transportation fuel is biomethane 

refined from biogas. Biogas is a term 

meaning a combustible mixture of 

methane and other light gases derived 

from biogenic sources. It can be 

combusted directly in some 

applications, but for use in highway 

vehicles it is typically purified to 

closely resemble fossil natural gas for 

which the vehicles are typically 

designed. The definition of biogas as 

given in EISA is sufficiently broad to 

cover combustible gases produced by 

biological decomposition of organic 

matter, as in a landfill or wastewater 

treatment facility, as well as those 

produced via thermochemical 

decomposition of biomass. 

Currently, the largest source of biogas 

is landfill gas collection, where the 

majority of fuel is combusted to generate 

electricity, with a small portion being 

upgraded to methane suitable for use in 

heavy duty vehicle fleets. Current 

literature suggests approximately 16 

billion gasoline gallons equivalent of 

biogas (referring to energy content) 

could potentially be produced in the 

long term, with about two thirds coming 

from biomass gasification and about one 

third coming from waste streams such 

as landfills and human and animal 

sewage digestion.59 60

Because the majority of the biogas 

volume estimates assume biomass as a 

feedstock, we have chosen not to 

include this fuel in our analyses since 

we are projecting most available 

biomass will be used for cellulosic 

liquid biofuel production in the long 

term. The remaining biogas potentially 

available from waste-related sources 

would come from a large number of 

small streams requiring purification and 

connection to storage and/or 

distribution facilities, which would 

involve significant economic hurdles. 

An additional and important source of 

uncertainty is whether there would be a 

sufficient number of vehicles configured 

to consume these volumes of biogas. 

Thus, we expect future biogas fuel 

streams to continue to find nontransportation uses such as electrical 

power generation or facility heating. 

d. Other Renewable Fuel 

The remaining portion of total 

renewable fuel not met with advanced 

biofuel is assumed to come from cornbased ethanol. EISA effectively sets a 

limit for participation in the RFS 

program of 15 Bgal of corn ethanol by 

2022. It should be noted, however, that 

there is no specific ‘‘corn-ethanol’’ 

mandated volume, and that any 

advanced biofuel produced above and 

beyond what is required for the 

advanced biofuel requirements could 

reduce the amount of corn ethanol 

needed to meet the total renewable fuel 

standard. This occurs in our projections 

during the earlier years (2009–2014) in 

which we project that some fuels could 

compete favorably with corn ethanol 

(e.g. biodiesel and imported ethanol). 

Beginning around 2015, fuels qualifying 

as advanced biofuels likely will be 

devoted to meeting the increasingly 

stringent volume mandates for advanced 

biofuel. It is also worth noting that more 

than 15 Bgal of corn ethanol could be 

produced and RINs generated for that 

volume under our proposed RFS2 

regulations. However, obligated parties 

would not be required to purchase more 

than 15 Bgal worth of corn ethanol 

RINs. 

We are assuming for our analysis that 

sufficient corn ethanol will be produced 

to meet the 15 Bgal limit. However, this 

assumes that in the future corn ethanol 

production is not limited due to 

environmental constraints, such as 

water quantity issues (see Section 6.10 

of the DRIA). This also assumes that in 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24983 

61Based on total transportation ethanol reported 

in EIA’s March 2009 Monthly Energy Review (Table 

10.2) less imports (http://tonto.eia.doe.gov/dnav/ 

pet/hist/mfeimus1a.htm). 62For more information on how the phase-out of 

MTBE helped spur ethanol production/ 

consumption, refer to Section V.D.1. 63On October 22, 2004, President Bush signed 

into law H.R. 4520, the American Jobs Creation Act 

of 2004 (JOBS Bill), which created the Volumetric 

Ethanol Excise Tax Credit (VEETC). The $0.51/gal 

VEETC for ethanol blender replaced the former fuel 

excise tax exemption, blender’s credit, and pure 

ethanol fuel credit. However, the recently-enacted 

2008 Farm Bill modifies the alcohol credit so that 

corn ethanol gets a reduced credit of $0.45/gal and 

cellulosic biofuel a credit of $1.01/gal effective 

January 1, 2009. 

64On May 1, 2007, EPA published a final rule (72 

FR 23900) implementing the Renewable Fuel 

Standard (RFS) required by EPAct. The RFS 

requires that 4.0 billion gallons of renewable fuel 

be blended into gasoline/diesel by 2006, growing to 

7.5 billion gallons by 2012. 

65Based on total transportation ethanol reported 

in EIA’s March 2009 Monthly Energy Review (Table 

10.2) less imports (http://tonto.eia.doe.gov/dnav/ 

pet/hist/mfeimus1a.htm). 

the future either corn ethanol plants are 

constructed or modified to meet the 

20% GHG threshold, or that sufficient 

corn ethanol production exists that is 

grandfathered and not required to meet 

the 20% threshold. Our current 

projection is that up to 15 Bgal could be 

grandfathered, but actual volumes will 

be determined at the time of facility 

registration. Refer to Section 1.5.1.4 of 

the DRIA for more information. Since 

our current lifecycle analysis estimates 

that much of the current corn ethanol 

would not meet the 20% GHG reduction 

threshold required of non-grandfathered 

facilities without facility upgrades, then 

if actual grandfathered corn volumes are 

less than 15 Bgal it may be necessary to 

meet the volume mandate with other 

renewable fuels or through the use of 

advanced technologies that could 

improve the corn ethanol lifecycle GHG 

estimates. 

B. Renewable Fuel Production 

1. Corn/Starch Ethanol 

The majority of domestic biofuel 

production currently comes from plants 

processing corn and other similarlyprocessed grains in the Midwest. 

However, there are a handful of plants 

located outside the Corn Belt and a few 

plants processing simple sugars from 

food or beverage waste. In this section, 

we will summarize the present state of 

the corn/starch ethanol industry and 

discuss how we expect things to change 

in the future under the proposed RFS2 

program. 

a. Historic/Current Production 

The United States is currently the 

largest ethanol producer in the world. In 

2008, the U.S. produced almost nine 

billion gallons of fuel ethanol for 

domestic consumption, the majority of 

which came from locally-grown corn.61

Although the U.S. ethanol industry has 

been in existence since the 1970s, it has 

rapidly expanded over the past few 

years due to the phase-out of methyl 

tertiary butyl ether (MTBE),62 elevated 

crude oil prices, state mandates and tax 

incentives, the introduction of the 

Federal Volume Ethanol Excise Tax 

Credit (VEETC),63 and the 

implementation of the existing RFS1 

program.64 As shown in Figure V.B.1–1, 

U.S. ethanol production has grown 

exponentially over the past decade. 


EP26MY09.004</GPH>
24984 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

66Our April 2009 corn/starch ethanol industry 

characterization was based on a variety of sources 

including: Renewable Fuels Association (RFA) 

Ethanol Biorefinery Locations (updated March 31, 

2009); Ethanol Producer Magazine (EPM) Producing 

plant list (last modified on April 7, 2009), and 

ethanol producer Web sites. The baseline does not 

include ethanol plants whose primary business is 

industrial or food-grade ethanol production nor 

does it include plants that might be located in the 

Virgin Islands or U.S. territories. Where applicable, 

current/historic production levels have been used 

in lieu of nameplate capacities to estimate 

production capacity. The April 2009 information 

presented in this section reflects our most recent 

knowledge of the corn/starch ethanol industry. 

However, for various NPRM impact analyses, an 

earlier May 2008 industry assessment was used. For 

more on this assessment, refer to Section 1.5.1.5 of 

the DRIA. 

67 In addition to idled plants, the assessment does 

not include idled production capacity at facilities 

that are currently operating at 50% or less than 

their nameplate capacity. 

68According to our April 2009 corn ethanol plant 

assessment, the average wet mill plant capacity was 

111 million gallons per year—almost twice that of 

the average dry mill plant capacity (62 million 

gallons per year). For more on average plant sizes, 

refer to Section 1.5.1.1 of the DRIA. 

69For more information on plant energy 

requirements, refer to Section 1.5.1.3 of the DRIA. 

70We are also aware of a couple plants that pull 

steam directly from a nearby utility. 

71Facilities were assumed to burn natural gas if 

the plant boiler fuel was unspecified or unavailable 

on the public domain. 

72For more on CHP technology, refer to Section 

1.4.1.3 of the DRIA. 

As of April 1, 2009, there were 169 

corn/starch ethanol plants operating in 

the U.S. with a combined estimated 

production capacity of 10.5 billion 

gallons per year.66 This does not include 

a number of ethanol plants that are 

currently idled.67 The majority of 

today’s ethanol (over 91% by volume) is 

produced exclusively from corn. 

Another 8% comes from a blend of corn 

and/or similarly processed grains (milo, 

wheat, or barley) and less than half a 

percent is produced from cheese whey, 

waste beverages, and sugars/starches 

combined. A summary of U.S. ethanol 

production by feedstock is presented in 

Table V.B.1–1. 

TABLE V.B.1–1—CURRENT CORN/STARCH ETHANOL PRODUCTION CAPACITY BY FEEDSTOCK

Plant feedstock 

(Primary listed first) 

Capacity 

MGY 

Percent of 

capacity 

Number of 

plants 

Percent of 

plants 

Corn a ............................................................................................................................... 9,605 91.2 144 85.2 

Corn, Milo b ...................................................................................................................... 717 6.8 14 8.3 

Corn, Wheat ..................................................................................................................... 130 1.2 1 0.6 

Milo .................................................................................................................................. 3 0.0 1 0.6 

Wheat, Milo ...................................................................................................................... 50 0.5 1 0.6 

Cheese Whey .................................................................................................................. 5 0.0 1 0.6 

Waste Beverages c .......................................................................................................... 19 0.2 5 3.0 

Waste Sugars & Starches d ............................................................................................. 7 0.1 2 1.2 

Total .......................................................................................................................... 10,535 100 169 100 

a Includes one facility processing seed corn, two facilities also operating pilot-level cellulosic ethanol plants at these locations, and four facilities 

planning on incorporating cellulosic feedstocks in the future. b Includes one facility processing a small amount of molasses in addition to corn and milo. 

c Includes two facilities processing brewery waste. 

d Includes one facility processing potato waste that intends to add corn in the future. 

As shown in Table V.B.1–1, of the 169 

operating plants, 161 process corn and/ 

or other similarly processed grains. Of 

these facilities, 150 utilize dry-milling 

technologies and the remaining 11 

plants rely on wet-milling processes. 

Dry mill ethanol plants grind the entire 

kernel and generally produce only one 

primary co-product: Distillers grains 

with solubles (DGS). The co-product is 

sold wet (WDGS) or dried (DDGS) to the 

agricultural market as animal feed. 

However, there are a growing number of 

dry mill ethanol plants pursuing frontend fractionation or back-end extraction 

to produce fuel-grade corn oil for the 

biodiesel industry. There are also 

additional plants pursuing cold starch 

fermentation and other energy-saving 

processing technologies. For more on 

the dry-milling and wet-milling 

processes as well as emerging advanced 

technologies, refer to Section 1.4 of the 

DRIA. 

In contrast to dry mill plants, wet mill 

facilities separate the kernel prior to 

processing into its component parts 

(germ, fiber, protein, and starch) and in 

turn produce other co-products (usually 

gluten feed, gluten meal, and food-grade 

corn oil) in addition to DGS. Wet mill 

plants are generally more costly to build 

but are larger in size on average.68 As 

such, 11.5% of the current grain ethanol 

production comes from the 11 

previously-mentioned wet mill 

facilities. The remaining eight plants 

which process cheese whey, waste 

beverages or sugars/starches, operate 

differently than their grain-based 

counterparts. These small production 

facilities do not require milling and 

operate a simpler enzymatic 

fermentation process. 

Ethanol production is a relatively 

resource-intensive process that requires 

the use of water, electricity, and 

steam.69 Steam needed to heat the 

process is generally produced on-site or 

by other dedicated boilers.70 The 

ethanol industry relies primarily on 

natural gas. Of today’s 169 ethanol 

production facilities, 142 burn natural 

gas 71 (exclusively), three burn a 

combination of natural gas and biomass, 

one recently started burning a 

combination of natural gas, landfill 

biogas and wood, and two burn a 

combination of natural gas and syrup 

from the process. In addition, 20 plants 

burn coal as their primary fuel and one 

burns a combination of coal and 

biomass. Our research suggests that 25 

plants currently utilize cogeneration or 

combined heat and power (CHP) 

technology, although others may exist. 

CHP is a mechanism for improving 

overall plant efficiency. Whether owned 

by the ethanol facility, their local utility, 

or a third party, CHP facilities produce 

their own electricity and use the waste 

heat from power production for process 

steam, reducing the energy intensity of 

ethanol production.72 A summary of the 

energy sources and CHP technology 

utilized by today’s ethanol plants is 

found in Table V.B.1–2. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24985 

73Farmer-owned plant status derived from 

Renewable Fuels Association (RFA), Ethanol 

Biorefinery Locations (updated March 31, 2009). 

For more on average plant sizes, refer to Section 

1.5.1 of the DRIA. 

74 Valero recently entered into the renewable 

fuels business by acquiring five idled corn ethanol 

plants and one construction site formerly owned by 

VeraSun Energy Corporation. Valero has since 

Continued 

TABLE V.B.1–2—CURRENT CORN/STARCH ETHANOL PRODUCTION CAPACITY BY ENERGY SOURCE

Plant energy source (primary listed first) Capacity 

MGY 

Percent of 

capacity 

Number of 

plants 

Percent of 

plants CHP tech. 

Coal a ........................................................................................................ 1,868 17.7 20 11.8 9 

Coal, Biomass .......................................................................................... 50 0.5 1 0.6 0 

Natural Gas b ............................................................................................ 8,294 78.7 142 84.0 15 

Natural Gas, Biomass c ............................................................................ 113 1.1 3 1.8 1 

Natural Gas, Landfill Biogas, Wood ........................................................ 110 1.0 1 0.6 0 

Natural Gas, Syrup .................................................................................. 101 1.0 2 1.2 0 

Total .................................................................................................. 10,535 100.0 169 100.0 25 

a Includes four plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to coal and one facility that intends 

to transition to biomas in the future. b Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage biogas, and two facilities that might switch 

to coal in the future. c Includes one facility processing bran in addition to natural gas. 

Since the majority of ethanol is made 

from corn, it is no surprise that most of 

the plants are located in the Midwest 

near the Corn Belt. Of today’s 169 

ethanol production facilities, 151 are 

located in the 15 states comprising 

PADD 2. For a map of the Petroleum 

Administration for Defense Districts or 

PADDs, refer to Figure V.B.1–2. 

As a region, PADD 2 accounts for 94% 

(or almost 10 billion gallons) of today’s 

estimated ethanol production capacity, 

as shown in Table V.B.1–3. For more 

information on today’s ethanol plants 

and a detailed map of their locations, 

refer to Section 1.5 of the DRIA. 

TABLE V.B.1–3—CURRENT CORN/STARCH ETHANOL PRODUCTION CAPACITY BY PADD 

PADD Capacity 

MGY 

Percent of 

capacity 

Number of 

plants 

Percent of 

plants 

PADD 1 ............................................................................................................................ 150 1.4 3 1.8 

PADD 2 ............................................................................................................................ 9,900 94.0 151 89.3 

PADD 3 ............................................................................................................................ 194 1.8 3 1.8 

PADD 4 ............................................................................................................................ 160 1.5 7 4.1 

PADD 5 ............................................................................................................................ 131 1.2 5 3.0 

Total .......................................................................................................................... 10,535 100.0 169 100.0 

The U.S. ethanol industry is currently 

comprised of a mixture of companyowned plants and locally-owned farmer 

cooperatives (co-ops). The majority of 

today’s ethanol production facilities are 

company-owned, and on average these 

plants are larger in size than farmerowned co-ops. Accordingly, companyowned plants account for more than 

79% of today’s ethanol production 

capacity.73 Furthermore, 30% of the 

total domestic product comes from 38 

plants owned by just three different 

companies—POET Biorefining, Archer 

Daniels Midland (ADM), and Valero 

Renewables.74


EP26MY09.005</GPH>
24986 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

purchased two more idled VeraSun plants, but they 

have not been brought back online yet. 75The lifecycle assessment values which assume 

a 2% discount rate over a 100-year timeframe. 

76 Idled plants and construction projects based on 

Renewable Fuels Association (RFA) Ethanol 

Biorefinery Locations (updated March 31, 2009); 

Ethanol Producer Magazine (EPM) Not Producing 

and Under Construction plant lists (last modified 

on April 7, 2009), ethanol producer Web sites, and 

follow-up correspondence with ethanol producers. 

It is worth noting that for our industry assessment, 

‘‘under construction’’ implies that more than just a 

ground breaking ceremony has taken place. 

77For more information on plant build rates, refer 

to Section 1.2.5 of the RIA. 

78For our NPRM impact analyses, we relied on 

an earlier May 2008 industry assessment. For more 

information, refer to Section 1.5.1.5 of the DRIA. 

b. Forecasted Production Under RFS2 

As highlighted above, 10.5 billion 

gallons of corn/starch ethanol plant 

capacity was online as of April 1, 2009. 

So even if no additional capacity was 

added, U.S. ethanol production would 

grow from 2008 to 2009, provided 

facilities continue to operate at or above 

today’s production levels. And despite 

today’s temporary unfavorable market 

conditions (i.e., low ethanol market 

values), we expect the ethanol industry 

will continue to expand in the future 

under RFS2. Although there is not a set 

corn ethanol standard, EISA allows for 

15 billion gallons of the 36-billion 

gallon renewable fuel standard to be met 

by conventional biofuels. And we 

expect that corn and other sugar or 

starch-based ethanol will fulfill this 

requirement. Furthermore, we project 

that all new corn/starch ethanol plant 

capacity brought online under RFS2 

would either meet the conventional 

biofuel GHG threshold requirement 75 or 

meet the grandfathering requirement 

(for more information, refer to Section 

1.5.1.4 of the DRIA). 

In addition to the 169 corn/starch 

ethanol plants that are currently online 

today, 36 plants are presently idled. 

Some of these constructed facilities 

(namely smaller ethanol plants) have 

been idled for quite some time, whereas 

other plants have just recently been put 

into ‘‘hot idle’’ mode. A number of 

ethanol producers (e.g., VeraSun) are 

idling operations, putting projects on 

hold, selling off plants, and even filing 

for Chapter 11 bankruptcy. In addition, 

we are aware of two facilities that are 

currently operating at 50% or less than 

their nameplate capacity. As crude oil 

and gasoline prices rise again in the 

future, corn ethanol production will 

become more viable again and we 

expect that these plants will resume 

operations. At the time of our April 

2009 ethanol industry assessment, there 

were also 19 new ethanol plants under 

construction in the U.S, and two plant 

expansion projects underway. While 

many of these projects are also on hold 

due to the current economic conditions, 

we expect these facilities will 

eventually come online under the RFS2 

program. A summary of the projected 

industry growth is found in Table 

V.B.1–4.76

TABLE V.B.1–4—POTENTIAL INDUSTRY EXPANSION UNDER RFS2 

Growth in ethanol production 

Plants 

currently 

online 

Idled plants/ 

capacity a

New 

construction 

projects 

Expansion 

projects Total 

Plant Capacity (MGY) .......................................................... 10,535 2,471 1,955 80 15,042 

Total No. of Plants ............................................................... 169 36 19 2 226 

a Includes the idled plant capacity of the two facilities that are currently operating at 50% or less than nameplate capacity. 

While theoretically it only takes 12 to 

18 months to build an ethanol plant,77

the rate at which new plant capacity 

comes online will be dictated by market 

conditions, which will in part be 

influenced by the RFS2 requirements. 

As mentioned above, today’s proposed 

program will create a growing demand 

for corn ethanol reaching 15 billion 

gallons by 2015. However, it is possible 

that market conditions could drive 

demand even higher. Whether the 

nation will overcomply with the corn 

ethanol standard is uncertain and will 

be determined by feedstock availability/ 

pricing, crude oil pricing, and the 

relative ethanol/gasoline price 

relationship. To measure the impacts of 

the proposed RFS2 program, we 

assumed that corn ethanol production 

would not exceed 15 billion gallons. We 

also assumed that all growth would 

come from new plants or plant 

expansion projects (in addition to idled 

plants being brought back online).78

However, it is possible that some of the 

growth could come from minor process 

improvements (e.g., debottlenecking) at 

existing facilities. 

Once all the aforementioned projects 

are complete, we project that there 

would be 226 corn/starch ethanol plants 

operating in the U.S. with a combined 

production capacity of around 15 billion 

gallons per year. Much like today’s 

ethanol industry, the overwhelming 

majority of new production capacity 

(93% by volume) is expected to come 

from corn-fed plants. Another 7% is 

forecasted to come from plants 

processing a blend of corn and other 

grains, and a very small increase is 

projected to come from idled cheese 

whey and waste beverage plants coming 

back online. A summary of the 

forecasted ethanol production by 

feedstock under the RFS2 program is 

found in Table V.B.1–5. 

TABLE V.B.1–5—PROJECTED RFS2 CORN/STARCH ETHANOL PRODUCTION CAPACITY BY FEEDSTOCK

Plant feedstock (primary listed first) 

Additional production Total RFS2 estimate 

Capacity 

MGY 

Number of 

plants 

Capacity 

MGY 

Number of 

plants 

Corn a ............................................................................................................................... 4,197 49 13,802 193 

Corn, Milo b ...................................................................................................................... 185 3 902 17 

Corn, Wheat ..................................................................................................................... 8 1 138 2 

Corn, Wheat, Milo ............................................................................................................ 110 2 110 2 

Milo .................................................................................................................................. 0 0 3 1 

Wheat, Milo ...................................................................................................................... 0 0 50 1 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24987 

79Facilities were assumed to burn natural gas if 

the plant boiler fuel was unspecified or unavailable 

on the public domain. 

80Two of the three coal-fired plant expansions 

appear as new plants in Table V.B.1–6. This is 

because two of the expansion projects consist of 

adding dry milling plant capacity to an existing wet 

mill plant. However, our interpretation is that these 

facilities will rely on the same (potentially 

expanded) coal-fired boilers for process steam. 

Since all the aforementioned coal-fired ethanol 

production facilities appear to have commenced 

construction prior to December 19, 2007, we project 

that the ethanol produced at these facilities will be 

grandfathered under the proposed RFS2 rule. For 

more on our grandfathered volume estimate, refer 

to Section 1.5.1.4 of the DRIA. 

TABLE V.B.1–5—PROJECTED RFS2 CORN/STARCH ETHANOL PRODUCTION CAPACITY BY FEEDSTOCK—Continued 

Plant feedstock (primary listed first) 

Additional production Total RFS2 estimate 

Capacity 

MGY 

Number of 

plants 

Capacity 

MGY 

Number of 

plants 

Cheese Whey .................................................................................................................. 3 1 8 2 

Waste Beverages c .......................................................................................................... 4 1 23 6 

Waste Sugars & Starches d ............................................................................................. 0 0 7 2 

Total .......................................................................................................................... 4,507 57 15,042 226 

a Includes one facility processing seed corn, another facility processing small amounts of whey, two facilities also operating pilot-level cellulosic 

ethanol plants at these locations, and four facilities planning on incorporating cellulosic feedstocks in the future. b Includes one facility processing a small amount of molasses in addition to corn and milo. 

c Includes two facilities processing brewery waste. 

d Includes one facility processing potato waste that intends to add corn in the future. 

Based on current industry plans, the 

majority of additional corn/grain 

ethanol production capacity (almost 

84% by volume) is predicted to come 

from new or expanded plants burning 

natural gas.79 Additionally, we are 

forecasting one new plant and a 

reopening of another plant relying on 

manure biogas. We are also predicting 

expansions at three coal-fired ethanol 

plants.80 Of the 55 new ethanol plants, 

our research indicates that five would 

utilize cogeneration, bringing the total 

number of CHP facilities to 30. A 

summary of the projected near-term 

ethanol plant energy sources is found in 

Table V.B.1–6. 

TABLE V.B.1–6—PROJECTED NEAR-TERM CORN/STARCH ETHANOL PRODUCTION CAPACITY BY ENERGY SOURCE

Plant energy source (primary listed first) 

Additional production Total RFS2 estimate 

Capacity 

MGY 

Number of 

plants 

Capacity 

MGY 

Number of 

plants CHP tech. 

Coal a ........................................................................................................ 610 2 2,478 22 11 

Coal, Biomass .......................................................................................... 0 0 50 1 0 

Manure Biogas ......................................................................................... 134 2 134 2 0 

Natural Gas b ............................................................................................ 3,763 53 12,056 195 18 

Natural Gas, Biomass c ............................................................................ 0 0 113 3 1 

Natural Gas, Landfill Biogas, Wood ........................................................ 0 0 110 1 0 

Natural Gas, Syrup .................................................................................. 0 0 101 2 0 

Total .................................................................................................. 4,507 57 15,042 226 30 

a Includes six plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to coal and one facility that intends 

to transition to biomass in the future. b Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage biogas, and six facilities that might switch 

to coal in the future. c Includes one facility processing bran in addition to natural gas. 

The information in Table V.B.1.6 is 

based on short-term industry production 

plans at the time of our April 1, 2009 

plant assessment. However, we are 

anticipating growth in advanced ethanol 

production technologies under the 

proposed RFS2 program. We project that 

fuel prices will drive a large number of 

corn ethanol plants to transition from 

conventional boiler fuels to advanced 

biomass-based feedstocks. We also 

believe that fossil fuel/electricity prices 

will drive a number of ethanol 

producers to pursue CHP technology. 

For more on our projected 2022 

utilization of these technologies under 

the RFS2 program, refer to Section 

1.5.1.3 of the DRIA. 

Under the proposed RFS2 program, 

the majority of new ethanol production 

is expected to originate from PADD 2, 

close to where most of the corn is 

grown. However, there are a number of 

‘‘destination’’ ethanol plants being built 

outside the Midwest in response to 

production subsidies, E10/E85 retail 

pump incentives, and state mandates. A 

summary of the forecasted ethanol 

production by PADD under the RFS2 

program can be found in Table V.B.1– 

7. 

24988 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

81Our April 2009 cellulosic ethanol industry 

characterization was based on researching DOEand USDA-supported projects, plants referenced in 

HART’s Ethanol & Biodiesel News (through the 

April 14, 2009 issue), plants included on the 

Cellulosic Ethanol Site (http://www.thecesite.com/), 

and plants referenced on other biofuel industry 

Web sites. 

TABLE V.B.1–7—PROJECTED RFS2 CORN/STARCH ETHANOL PRODUCTION CAPACITY BY PADD 

PADD 

Additional production Total RFS2 Estimate 

Capacity 

MGY 

Number of 

plants 

Capacity 

MGY 

Number of 

plants 

PADD 1 ............................................................................................................................ 178 3 328 6 

PADD 2 ............................................................................................................................ 3,566 43 13,466 194 

PADD 3 ............................................................................................................................ 350 4 544 7 

PADD 4 ............................................................................................................................ 50 1 210 8 

PADD 5 ............................................................................................................................ 363 6 494 11 

Total .......................................................................................................................... 4,507 57 15,042 226 

2. Cellulosic Biofuel 

Ethanol currently dominates U.S. 

biofuel production, and more 

specifically, ethanol produced from 

corn and other grains. However, 

cellulosic feedstocks have the potential 

to greatly expand domestic ethanol 

production, both volumetrically and 

geographically. It is also possible to 

produce synthetic diesel fuel from 

cellulosic feedstocks (also known as 

‘‘cellulosic diesel’’) through a FischerTropsch gasification process or a 

thermal depolymerization process. We 

are also aware of one company using 

live bacteria to break down biomass and 

produce cellulosic diesel and other 

petroleum replacements. Before widescale commercialization of cellulosic 

biofuel can occur in today’s 

marketplace, technical and logistical 

barriers must be overcome. In addition 

to today’s RFS2 program which sets 

aggressive goals for all ethanol 

production, the Department of Energy 

(DOE) and other federal and state 

agencies are helping to spur industry 

growth. 

a. Current Production/Plans 

The cellulosic biofuel industry is 

essentially in its infancy. With the 

exception of a 20 million-gallon-per 

year cellulosic diesel plant recently 

opened by Cello Energy in Bay Minette, 

AL, the majority of facilities in 

operation today are small pilot- or 

demonstration-level plants. Most of 

these facilities operate intermittently 

and produce insignificant volumes of 

biofuel. Some researchers are focusing 

on processing corn residues, e.g., corn 

stover, cobs, and/or fiber. Some are 

focusing on other agricultural residues 

such as sugarcane bagasse, rice and 

wheat straw. Others are looking at waste 

products such as forestry residues, 

citrus residues, pulp or paper mill 

waste, municipal solid waste (MSW), 

and construction and demolition (C&D) 

debris. Dedicated energy crops 

including switchgrass and poplar trees 

are also being investigated. 

Based on an April 2009 assessment of 

information available on the public 

domain, there are currently 25 pilotand demonstration-level (or smaller) 

cellulosic ethanol plants operating in 

the United States. However, only 9 of 

these plants report measurable volumes 

of ethanol production. In addition, we 

are aware of one pilot-level cellulosic 

diesel plant in addition to the 

commercial-level Cello Energy plant.81

A summary of these 11 facilities totaling 

just over 23 million gallons of annual 

production capacity is provided in 

Table V.B.2–1. The date listed in the 

table indicates when the facility first 

began operations. For more on the 

existing cellulosic ethanol and diesel 

plants, refer to Sections 1.5.3.1 and 

1.5.3.3 of the DRIA. 

TABLE V.B.2–1—EXISTING CELLULOSIC BIOFUEL PLANTS

Company or organization name Location Feedstocks 

Prod 

cap 

(MGY) 

Est. 

Op. 

date 

Conv. 

tech. a

Cellulosic Ethanol 

Abengoa Bioenergy Corporation b ................... York, NE ............. Wheat straw, corn stover, energy crops ........ 0.02 Sep-07 Bio. 

Bioengineering Resources, Inc. (BRI) ............. Fayetteville, AR .. MSW, wood waste, coal ................................. 0.04 1998 Therm. 

BPI & Universal Entech ................................... Phoenix, AZ ........ Paper waste (sorted MSW) ............................ 0.01 2004 Bio. 

Gulf Coast Energy ........................................... Livingston, AL ..... Wood waste (sorted MSW) ............................ 0.20 Dec-08 Therm. 

Mascoma Corporation ..................................... Rome, NY ........... Wood chips ..................................................... 0.20 Feb-09 Bio. 

POET Project Bell b ......................................... Scotland, SD ....... Corn cobs & fiber ............................................ 0.02 Jan-09 Bio. 

Verenium ......................................................... Jennings, LA ....... Sugarcane bagasse ........................................ 0.05 2006 Bio. 

Verenium ......................................................... Jennings, LA ....... Sugarcane bagasse, wood, energy cane ....... 1.50 Feb-09 Bio. 

Western Biomass Energy LLC. (WBE) ........... Upton, WY .......... Wood waste (softwood) .................................. 1.50 2007 Bio. 

Cellulosic Diesel 

Cello Energy .................................................... Bay Minette, AL .. Wood chips, hay ............................................. 20.00 Dec-08 CatDep. 

Bell BioEnergy ................................................. Fort Stewart, GA Wood chips ..................................................... 0.01 Dec-08 Bact. 

Total Existing Production Capacity >23 MGY 

aBio = biochemical pre-treatment, Therm = thermochemical conversion, CatDep = catalytic depolymerization, Bact = involves the use of live 

bacteria to break down biomass for cellulosic diesel production. b Cellulosic pilot plant is collocated with a corn ethanol plant. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24989 

82Range Fuels’ ultimate goal is to expand the 

Soperton, GA facility to produce 100 million 

gallons of cellulosic ethanol per year. 

To date, the majority of cellulosic 

ethanol research has focused on 

biochemical pre-treatment technologies, 

i.e., the use of acids and/or enzymes to 

break down cellulosic materials into 

fermentable sugars. However, there are 

a growing number of companies 

investigating the thermochemical 

pathway which involves gasification of 

biomass into a synthesis gas or pyrolysis 

of biomass into a bio-crude oil for 

processing. Cellulosic diesel can also be 

made from thermochemical as well as 

other processes. Many companies are 

also researching the potential of cofiring biomass to produce plant energy 

in addition to biofuels. For more on 

cellulosic biofuel processing 

technologies, refer to Section 1.4.3 of 

the DRIA. 

In addition to the existing facilities in 

Table V.B.2–1, our April 2009 industry 

assessment suggests that there are 

currently three cellulosic ethanol plants 

under construction in the United States. 

Like the existing plants, two are pilotlevel facilities that are still working 

towards proving their conversion 

technologies. However, Range Fuels, a 

company that received $76 million from 

DOE and an $80 loan guarantee from 

USDA to build one of the first 

commercial-scale cellulosic ethanol 

plants in the U.S., is currently building 

a 40 million gallon per year plant in 

Soperton, GA.82 At this time, the 

company is just working on the initial 

10 million gallon per year phase. Bell 

Bioenergy, a company that received $7.5 

million in funding from the Department 

of Defense to convert biomass into 

cellulosic diesel using live bacteria, also 

has six pilot plants under construction 

in various locations through the 

country. A summary of these nine 

cellulosic biofuel plants, totaling over 

10 million gallons of annual production 

capacity, is presented in Table V.B.2–2. 

As shown in Tables V.B.2–1 and 

V.B.2–2, unlike corn ethanol 

production, which is primarily located 

in the Midwest near the Corn Belt, 

cellulosic biofuel production is spread 

throughout the country. The geographic 

distribution of plants is due to the wide 

variety and availability of cellulosic 

feedstocks. Corn stover is found 

primarily in the Midwest, while the 

Pacific Northwest, the Northeast, and 

the Southeast all have forestry residues. 

Some southern states have access to 

sugarcane bagasse and citrus waste 

while MSW and C&D debris are 

available in highly populated areas 

throughout the country. For more 

information on cellulosic feedstock 

availability, refer to Section 1.1.2 of the 

DRIA. 

TABLE V.B.2–2—CELLULOSIC BIOFUEL PLANTS CURRENTLY UNDER CONSTRUCTION

Company plant name Location Feedstocks 

Prod 

cap 

(MGY) 

Est. 

op. 

date. 

Conv. 

tech. a

Cellulosic Ethanol 

Coskata ............................................................ Madison, PA ....... MSW, natural gas, woodchips, bagasse, 

switchgrass.

0.04 Jul–09 Therm. 

DuPont Dansico Cellulosic Ethanol (DDCE) ... Vonore, TN ......... Corn cobs then switchgrass ........................... 0.25 Dec– 

09 

Bio. 

Range Fuels b .................................................. Soperton, GA ...... Wood waste, switchgrass ............................... 10.00 Dec– 

09 

Therm. 

Cellulosic Diesel 

Bell Bio-Energy ................................................ Fort Lewis, WA ... Cellulose ......................................................... 0.01 2009 Bact. 

Bell Bio-Energy ................................................ Fort Drum, NY .... Cellulose ......................................................... 0.01 2009 Bact. 

Bell Bio-Energy ................................................ Fort AP Hill, VA .. Cellulose ......................................................... 0.01 2009 Bact. 

Bell Bio-Energy ................................................ Fort Bragg, NC ... Cellulose ......................................................... 0.01 2009 Bact. 

Bell Bio-Energy ................................................ Fort Benning, GA Cellulose ......................................................... 0.01 2009 Bact. 

Bell Bio-Energy ................................................ San Pedro, CA ... Cellulose ......................................................... 0.01 2009 Bact. 

Total Under Construction Production Capacity >10 MGY 

aBio = biochemical pre-treatment, Therm = thermochemical conversion, Bact = involves the use of live bacteria to break down biomass for cellulosic diesel production. bThe first 10 MGY phase is currently under construction in Soperton, GA. Once this second 30 MGY phase is added, the plant will be capable 

of producing 40 MGY of cellulosic ethanol. 

Increased public interest, government 

support, technological advancement, 

and the recently-enacted EISA have 

helped spur many plans for new 

cellulosic biofuel plants. Although more 

and more plants are being announced, 

most are limited in size and contingent 

upon technology breakthroughs and 

efficiency improvements at the pilot or 

demonstration level. Additionally, 

because cellulosic biofuel production 

has not yet been proven on the 

commercial level, financing of these 

projects has primarily been through 

venture capital and similar funding 

mechanisms, as opposed to 

conventional bank loans. 

Consequently, recently-announced 

Federal grant and loan guarantee 

programs may serve as a significant 

asset to the cellulosic biofuel industry 

in this area. In February 2007, DOE 

announced that it would invest up to 

$385 million in six commercial-scale 

ethanol projects over the next four 

years. Since the announcement, two of 

the companies have forfeited their 

funding. Iogen has decided to locate its 

first commercial-scale plant in Canada 

and Alico has discontinued plans to 

produce ethanol all together. The four 

remaining ‘‘pioneer’’ plants (including 

Range Fuels) hold promise and could 

very well be some of the first plants to 

demonstrate the commercial-scale 

viability of cellulosic ethanol 

production. However, there is still more 

to be learned at the pilot level. Although 

technologies needed to convert 

24990 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

83 Iogen and Alico have also forfeited a potential 

loan guarantee from DOE. 

cellulosic feedstocks into ethanol (and 

diesel) are becoming more and more 

understood, there are still a number of 

efficiency improvements that need to 

occur before cellulosic biofuels can 

compete in today’s marketplace. 

In May 2007, DOE announced that it 

would provide up to $200 million to 

help fund small-scale cellulosic 

biorefineries experimenting with novel 

processing technologies that could later 

be expanded to commercial production 

facilities. Four recipients were 

announced in January 2008 and three 

more were announced in April 2008. 

Three months later, DOE announced 

that it would provide $40 million more 

to help fund two additional small-scale 

plants. Of the nine announced smallscale plants, seven were pursuing 

cellulosic ethanol production (including 

Verenium Corp.) and two are pursuing 

cellulosic diesel production. However, 

Lignol Innovations, recently suspended 

plans to build a 2.5 million gallon per 

year cellulosic ethanol plant in Grand 

Junction, CO due to market uncertainty. 

The Department of Energy has also 

introduced a loan guarantee program to 

help reduce risk and spur investment in 

projects that employ new, clean energy 

technologies. In October 2007, DOE 

issued final regulations and invited 16 

project sponsors who submitted preapplications to submit full applications 

for loan guarantees. Of those who were 

invited to participate, five were 

pursuing cellulosic biofuel production. 

However, only three companies appear 

to still be eligible.83 Of the three 

remaining companies, two are pursuing 

cellulosic ethanol production (and are 

also DOE grant recipients) and one is 

pursuing cellulosic diesel production. 

The U.S. Department of Agriculture is 

also providing an $80 million loan 

guarantee to Range Fuels to help 

support construction of its 40 milliongallon-per-year cellulosic ethanol plant 

in Soperton, GA. For more on 

information on Federal support for 

biofuel production, refer to Section 1.5.3 

of the DRIA. 

In addition to the companies 

receiving government funding, there are 

a growing number of privately-funded 

companies (including Cello Energy) 

with plans to build more cellulosic 

biofuel plants in the United States. 

These facilities range in size from pilotand demonstration-level plants (similar 

to those currently operational or under 

construction), to small commercial 

plants (similar to the four commercialscale plants receiving DOE funding), to 

large commercial plants (similar in size 

to an average corn ethanol plant). These 

projects are also at various stages of 

planning. According to our April 2009 

industry assessment, 11 plants are 

currently at advanced stages of planning 

and likely to go online in the near 

future. Along with those plants 

currently operational or under 

construction, we believe that these 

facilities will enable the U.S. to meet the 

100 million gallon cellulosic biofuel 

standard in 2010. For a summary of the 

plants and their respective projected 

contributions, refer to Table V.B.2–3 

below. For a greater discussion on these 

and other cellulosic biofuel projects, 

refer to Section 1.5.3.1 of the DRIA. 

TABLE V.B.2–3—PROJECTED CELLULOSIC BIOFUEL PRODUCTION IN 2010 

Company or organization name Location Prod cap 

(MGY) Est. op. date 

Est. 2010 

million 

gallons 

Est 2010 

ETOHequiv. 

million 

gallons 

Cellulosic Ethanol 

BPI & Universal Entech ........................ Phoenix, AZ ......................................... 0.01 Online ............................. 0.01 0.01 

POET Project Bell ................................ Scotland, SD ....................................... 0.02 Online ............................. 0.02 0.02 

Abengoa Bioenergy Corporation .......... York, NE .............................................. 0.02 Online ............................. 0.02 0.02 

Bioengineering Resources, Inc. (BRI) .. Fayetteville, AK ................................... 0.04 Online ............................. 0.04 0.04 

Verenium .............................................. Jennings, LA ........................................ 0.05 Online ............................. 0.05 0.05 

Gulf Coast Energy ................................ Livingston, AL ...................................... 0.20 Online ............................. 0.20 0.20 

Mascoma Corporation .......................... Rome, NY ............................................ 0.20 Online ............................. 0.20 0.20 

Verenium .............................................. Jennings, LA ........................................ 1.50 Online ............................. 1.50 1.50 

Western Biomass Energy, LLC. (WBE) Upton, WY ........................................... 1.50 Online ............................. 1.50 1.50 

Coskata ................................................ Madison, PA ........................................ 0.04 Jul-09 .............................. 0.04 0.04 

DuPont Dansico Cellulosic Ethanol 

(DDCE).

Vonore, TN .......................................... 0.25 Dec-09 ............................ 0.25 0.25 

Range Fuels ......................................... Soperton, GA ....................................... 10.0 Dec-09 ............................ 10.0 10.0 

Ecofin/Alltech ........................................ Springfield, KY ..................................... 1.30 2010 ................................ 0.65 0.65 

Fulcrum Bioenergy ............................... Storey County, NV .............................. 10.50 2010 ................................ 5.25 5.25 

ICM Inc. ................................................ St. Joseph, MO ................................... 1.50 2010 ................................ 0.75 0.75 

RSE Pulp & Chemical .......................... Old Town, ME ..................................... 2.20 2010 ................................ 1.10 1.10 

ZeaChem .............................................. Boardman, OR .................................... 1.50 2010 ................................ 0.75 0.75 

ClearFuels Technology ........................ Kauai, HI .............................................. 1.50 End of 2010 .................... 0.38 0.38 

Southeast Renewable Fuels LLC ........ Clewiston, FL ....................................... 20.00 End of 2010 .................... 5.00 5.00 

Cellulosic Diesel 

Cello Energy ......................................... Bay Minette, AL ................................... 20.00 Online ............................. 20.00 32.00 

Bell Bio-Energy ..................................... Fort Stewart, GA ................................. 0.01 2008 ................................ 0.01 0.01 

Bell Bio-Energy ..................................... Fort Lewis, WA .................................... 0.01 2009 ................................ 0.01 0.01 

Bell Bio-Energy ..................................... Fort Drum, NY ..................................... 0.01 2009 ................................ 0.01 0.01 

Bell Bio-Energy ..................................... Fort AP Hill, VA ................................... 0.01 2009 ................................ 0.01 0.01 

Bell Bio-Energy ..................................... Fort Bragg, NC .................................... 0.01 2009 ................................ 0.01 0.01 

Bell Bio-Energy ..................................... Fort Benning, GA ................................ 0.01 2009 ................................ 0.01 0.01 

Bell Bio-Energy ..................................... San Pedro, CA .................................... 0.01 2009 ................................ 0.01 0.01 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24991 

84For more on state-level biodiesel production 

incentives, refer to Section 1.5.4 of the DRIA. 

85The database of ethanol incentives and laws by 

state is available at: http://www.eere.energy.gov/ 

afdc/ethanol/incentives_laws.html. 

86Midwest Governors Association, ‘‘Energy 

Security and Climate Stewardship Platform for the 

Midwest 2007’’ (http:// 

www.midwesterngovernors.org/resolutions/ 

Platform.pdf) 

87The Food, Conservation, and Energy Act of 

2008 (http://www.usda.gov/documents/ 

Bill_6124.pdf) 

88Refer to Part II, Subparts A and B (Sections 

15321 and 15331). 

TABLE V.B.2–3—PROJECTED CELLULOSIC BIOFUEL PRODUCTION IN 2010—Continued 

Company or organization name Location Prod cap 

(MGY) Est. op. date 

Est. 2010 

million 

gallons 

Est 2010 

ETOHequiv. 

million 

gallons 

Cello Energy ......................................... TBD (AL) ............................................. 50.00 2010 ................................ 16.67 26.67 

Cello Energy ......................................... TBD (AL) ............................................. 50.00 2010 ................................ 16.67 26.67 

Cello Energy ......................................... TBD (GA) ............................................. 50.00 2010 ................................ 16.67 26.67 

Flambeau River Biofuels ...................... Park Falls, WI ...................................... 6.00 2010 ................................ 3.00 4.80 

Total 2010 Production Forecast .... .............................................................. ................ ......................................... 100.74 144.57 

b. Federal/State Production Incentives 

In addition to helping fund a series of 

small-scale cellulosic biofuel plants, the 

Department of Energy, along with the 

U.S. Department of Agriculture (USDA), 

is also helping to fund critical research 

to help make cellulosic biofuel 

production more commercially viable. 

In March 2007, DOE awarded $23 

million in grants to four companies and 

one university to develop more efficient 

microbes for ethanol refining. In June 

2007, DOE and USDA awarded $8.3 

million to 10 universities, laboratories, 

and research centers to conduct 

genomics research on woody plant 

tissue for bioenergy. Later that same 

month, DOE announced plans to spend 

$375 million to build three bioenergy 

research centers dedicated to 

accelerating research and development 

of cellulosic ethanol and other biofuels. 

The centers, which will each focus on 

different feedstocks and biological 

research challenges, will be located in 

Oak Ridge, TN, Madison, WI, and 

Berkeley, CA. In December 2007, DOE 

awarded $7.7 million to one company, 

one university, and two research centers 

to demonstrate the thermochemical 

conversion process of turning grasses, 

stover, and other cellulosic materials 

into biofuel. In February 2008, DOE 

awarded another $33.8 million to three 

companies and one research center to 

support the development of 

commercially-viable enzymes to support 

cellulose hydrolysis, a critical step in 

the biochemical breakdown of cellulosic 

feedstocks. Finally, in March 2008, DOE 

and USDA awarded $18 million to 18 

universities and research institutes to 

conduct research and development of 

biomass-based products, biofuels, 

bioenergy, and related processes. Since 

2007, DOE has announced more than $1 

billion and since 2006, USDA has 

invested almost $600 million for the 

research, development, and 

demonstration of new biofuel 

technology. 

Numerous states are also offering 

grants, tax incentives, and loan 

guarantees to help encourage biofuel 

production. The majority of efforts are 

centered on expanding ethanol 

production, and more recently, 

cellulosic ethanol production.84

According to a July 2008 assessment of 

DOE’s Energy Efficiency and Renewable 

Energy (EERE) Web site,85 33 states 

currently offer some form of ethanol 

production incentive. The incentives 

range from support for ethanol 

producers to support for research and 

development companies to support for 

feedstock suppliers. Kansas, Maryland, 

and South Carolina each offer specific 

incentives towards cellulosic ethanol 

production. Kansas offers revenue 

bonds through the Kansas Development 

Finance Authority to help fund 

construction or expansion of a cellulosic 

ethanol plant. Additionally, these 

newly-built or expanded facilities are 

exempt from state property tax for 10 

years. Maryland offers a credit towards 

state income tax for 10% of cellulosic 

ethanol research and development 

expenses. They also have a $0.20 per 

gallon production credit for cellulosic 

ethanol. South Carolina gives a $0.30 

per gallon production credit to 

cellulosic ethanol producers that meet 

certain requirements. 

In addition to individual state 

incentives, a group of states in the 

Midwest have joined together to pursue 

ethanol and other biofuel production 

and usage goals as part of the Midwest 

Energy Security and Climate 

Stewardship Platform.86 As of June 

2008, Indiana, Iowa, Kansas, Michigan, 

Minnesota, North Dakota, Ohio, South 

Dakota, and Wisconsin had all 

committed to these goals which 

emphasize energy independence 

through the growth of cellulosic ethanol 

production and availability of E85. The 

Platform goals are to produce cellulosic 

ethanol on a commercial level by 2012 

and to have E85 offered at one-third of 

refueling stations by 2025. They also 

want to reduce the energy intensity of 

ethanol production and supply 50% of 

their transportation fuel needs by 

regionally produced biofuels by 2025. 

Finally, the passage of the Food, 

Conservation, and Energy Act of 2008 

(also known as the ‘‘2008 Farm Bill’’) is 

also helping to spur cellulosic ethanol 

production and use.87 The 2008 Farm 

Bill modified the existing $0.51 per 

gallon alcohol blender credit to give 

preference to ethanol and other biofuels 

produced from cellulosic feedstocks. 

Corn ethanol now receives a reduced 

credit of $0.45/gal while cellulosic 

biofuel earns a credit of $1.01/gal.88 The 

2008 Farm Bill also has provisions that 

enable USDA to assist with the 

commercialization of second-generation 

biofuels. Section 9003 authorizes loan 

guarantees for the development, 

construction and retrofitting of 

commercial scale biorefineries. Section 

9004 provides payments to biorefineries 

to replace fossil fuels with renewable 

biomass. Section 9005 provides 

payments to producers to support and 

ensure production of advanced biofuels. 

And finally, Section 9008 provides 

competitive grants, contracts and 

financial assistance to enable eligible 

entities to carry out research, 

development, and demonstration of 

biofuels and biomass-based based 

products. For more information on the 

Federal and state production incentives 

outlined in this subsection, refer to 

Section 1.5.3.2 of the DRIA. 

c. Feedstock Availability 

A wide variety of feedstocks can be 

used for cellulosic ethanol production, 

including: Agricultural residues, 

24992 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

89 It is important to note that our plant siting 

analysis for cellulosic ethanol facilities used the 

most current version of outputs from FASOM at the 

time, which was from April 2008. Since then, 

FASOM has been updated to reflect better 

assumptions. Therefore, the version used for the 

NPRM in Section IX on economic impacts is 

slightly different than the one we used here. We do 

not believe that the differences between the two 

versions are enough to have a major impact on the 

plant siting analysis. 

90The FASOM results do not take into 

consideration these feedstock safety margins. Safety 

margins were used, however, for the plant siting 

analysis described in Section V.B.2.c.v. 

91EPA. Municipal Solid Waste Generation, 

Recycling, and Disposal in the United States: Facts 

and Figures for 2006. 92Fehrs, J., ‘‘Secondary Mill Residues and Urban 

Wood Waste Quantities in the United States—Final 

Report,’’ Northeast Regional Biomass Program 

Washington, DC, December 1999. 

93Wiltsee, G., ‘‘Urban Wood Waste Resource 

Assessment,’’ NREL/SR–570–25918, National 

Renewable Energy Laboratory, November 1998. 

94Biocycle, ‘‘The State of Garbage in America,’’ 

Vol. 47, No. 4, 2006, p. 26. 

forestry biomass, municipal solid waste, 

construction and demolition waste, and 

energy crops. These feedstocks are 

much more difficult to convert into 

ethanol than traditional starch/corn 

crops or at least require new and 

different processes because of the more 

complex structure of cellulosic material. 

One potential barrier to commercially 

viable cellulosic biofuel production is 

high feedstock cost. As such, fuel 

producers will seek to acquire 

inexpensive feedstocks in sufficient 

quantities to lower their production 

costs and the risk of feedstock supply 

shortages. At least initially, the focus 

will be on feedstocks that are readily 

available, already produced or collected 

for other reasons, and even waste 

biomass which currently incurs a 

disposal fee. Consequently, initial 

volumes of cellulosic biofuels may 

benefit from low-cost feedstocks. 

However, to reach 16 Bgal will likely 

require reliance on more expensive 

feedstock sources purposely grown and 

or harvested for conversion into 

cellulosic biofuel. 

To determine the likely cellulosic 

feedstocks for production of 16 billion 

gallons cellulosic biofuel by 2022, we 

analyzed the data and results from 

various sources. Sources include 

agricultural modeling from the Forestry 

Agriculture Sector Optimization Model 

(FASOM) to establish the most 

economical agriculture residues and 

energy crops (see Section IX for more 

details on the FASOM), consultation 

with USDA–Forestry Sector experts for 

forestry biomass supply curves, and 

feedstock assessment estimates for 

urban waste.89

An important assumption in our 

analysis projecting which feedstocks 

will be used for producing cellulosic 

ethanol is that an excess of feedstock 

would have to be available for 

producing the biofuel. Banks are 

anticipated to require excess feedstock 

supply as a safety factor to ensure that 

the plant will have adequate feedstock 

available for the plant, despite any 

feedstock emergency, such as a fire, 

drought, infestation of pests etc. For our 

analysis we assumed that twice the 

feedstock of MSW, C&D waste, and 

forest residue would have to be 

available to justify the building of a 

cellulosic ethanol plant. For corn stover, 

we assumed 50% more feedstock than 

necessary. We used a lower safety factor 

for corn stover because it could be 

possible to remove a larger percentage of 

the corn stover in any given year 

(usually only 50% or less of corn stover 

is assumed to be sustainably removed in 

any one year).90 As a result, our 

projected cellulosic facilities only 

consume a portion of the total supply of 

feedstock available. After a cellulosic 

facility is fully established and certain 

risks are reduced, it is entirely possible 

that the facility may choose to consume 

excess feedstock in order to expand 

production. In addition, more facilities 

could potentially be built if financial 

investors required less excess supply. 

Since we are assessing the impact of 

producing 16 Bgal of cellulosic biofuel 

by 2022, this analysis does not project 

the construction of more facilities or 

more feedstocks consumed than 

necessary. 

Another assumption that we made is 

that if multiple feedstocks are available 

in an area, each would be used as 

feedstocks for a prospective cellulosic 

ethanol plant. For example, a particular 

area might comprise a small or medium 

sized city, some forest and some 

agricultural land. We would include the 

MSW and C&D wastes available from 

the city along with the corn stover and 

forest residue for projecting the 

feedstock that would be processed by 

the particular cellulosic ethanol plant. 

The following subsections describe 

the availability of various cellulosic 

feedstocks and the estimated amounts 

from each feedstock needed to meet the 

EISA requirement of 16 Bgal of 

cellulosic biofuel by 2022. Refer to 

Section V.B.2.c.iv for the summarized 

results of the types and volumes of 

cellulosic feedstocks chosen based on 

our analyses. 

i Urban Waste 

Cellulosic feedstocks available at the 

lowest cost to the ethanol producer will 

likely be chosen first. This suggests that 

urban waste which is already being 

gathered today and which incurs a fee 

for its disposal may be among the first 

to be used. Urban wood wastes are used 

in a variety of ways. Most commonly, 

wastes are ground into mulch, dumped 

into land-fills, or incinerated with other 

municipal solid waste (MSW) or 

construction and demolition (C&D) 

debris. Urban wood wastes include a 

variety of wood resources such as woodbased municipal solid waste and wood 

debris from construction and 

demolition. 

MSW consists of paper, glass, metals, 

plastics, wood, yard trimmings, food 

scraps, rubber, leather, textiles, etc. The 

portion of MSW containing cellulosic 

material and typically the focus for 

biofuel production is wood and yard 

trimmings. In addition, paper, which 

made up approximately 34% of the total 

MSW generated in 2006, could 

potentially be converted to cellulosic 

biofuel.91 Food scraps could also be 

converted to cellulosic biofuel, 

however, it was noted by an industry 

group that this feedstock could be more 

difficult to convert to biofuel due to 

challenges with separation, storage, 

transport, and degradation of the 

materials. Although recycling/recovery 

rates are increasing over time, there 

appears to still be a large fraction of 

biogenic material that ends up unused 

and in land-fills. C&D debris is typically 

not available in wood waste 

assessments, although some have 

estimated this feedstock based on 

population. In 1996, this was estimated 

to be approximately 124 million metric 

tons of C&D debris.92 Only a portion of 

this, however, would be made of woody 

material. Utilization of such feedstocks 

could help generate energy or biofuels 

for transportation. However, despite 

various assessments on urban waste 

resources, there is still a general lack of 

reliable data on delivered prices, issues 

of quality (potential for contamination), 

and lack of understanding of potential 

competition with other alternative uses 

(e.g. recycling, burning for electricity). 

We estimated that 42 million dry tons 

of MSW (wood and yard trimmings & 

paper) and C&D wood waste could be 

available for producing biofuels after 

factoring in several assumptions (e.g. 

percent contamination, percent 

recovered or combusted for other uses, 

and percent moisture).93 94 We assumed 

that approximately 25 million dry tons 

(of the total 42 million dry tons) would 

be used. However, many areas of the 

U.S. (e.g. much of the Rocky Mountain 

States) have such sparse resources that 

a MSW and C&D cellulosic facility 

would not likely be justifiable. We did 

assume that in areas with other 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24993 

95Assuming 90 gal/dry ton ethanol conversion 

yield for urban waste in 2022. 96Chambers, J., ‘‘Hurricane Katrina’s Carbon 

Footprint on U.S. Gulf Coast Forests’’ Science Vol. 

318, 2007. 

97Elbehri, Aziz. USDA, ERS. ‘‘An Evaluation of 

the Economics of Biomass Feedstocks: A Synthesis 

of the Literature. Prepared for the Biomass Research 

and Development Board,’’ 2007; Since 2007, a final 

report has been released. Biomass Research and 

Development Board, ‘‘The Economics of Biomass 

Feedstocks in the United States: A Review of the 

Literature,’’ October 2008. 

98 Graham, R.L., ‘‘Current and Potential U.S. Corn 

Stover Supplies,’’ American Society of Agronomy 

99:1–11, 2007. 

99Wilhelm, W.W. et. al., ‘‘Corn Stover to Sustain 

Soil Organic Carbon Further Constrains Biomass 

Supply,’’ Agron. J. 99:1665–1667, 2007. 

cellulosic feedstocks (forest and 

agricultural residue), that the MSW 

would be used even if the MSW could 

not justify the installation of a plant on 

its own. Therefore, we have estimated 

that urban waste could help contribute 

to the production of approximately 2.2 

billion gallons of ethanol.95 A more 

detailed discussion on this analysis is 

included in the DRIA Chapter 1. 

Subsequent to initiating our analysis, 

however, we realized that the revised 

renewable biomass definition in the 

statute may preclude the use of most 

MSW. See Section III.B.4 for a 

discussion of renewable biomass. When 

the definition of renewable biomass is 

finalized, it could preclude the use of 

some of the lowest cost potential 

feedstocks, including waste paper and 

C&D waste, for use in producing 

cellulosic biofuel for use toward the 

RFS2 standard. If this is the case, then 

our FRM analysis will be adjusted to 

reflect this. 

In addition to MSW and C&D waste 

generated from normal day-to-day 

activities, there is also potential for 

renewable biomass to be generated from 

natural disasters. This includes diseased 

trees, other woody debris, and C&D 

debris. For instance, Hurricane Katrina 

was estimated to have damaged 

approximately 320 million large trees.96

Katrina also generated over 100 million 

tons of residential debris, not including 

the commercial sector. The material 

generated from these situations could 

potentially be used to generate 

cellulosic biofuel. While we 

acknowledge this material could 

provide a large source in the short-term, 

natural disasters are highly variable, 

making it hard to predict future volumes 

that could be generated. We seek 

comment on how to take into account 

such estimates to be included in future 

feedstock availability analyses. 

ii. Agricultural and Forestry Residues 

The next category of feedstocks 

chosen will likely be those that are 

readily produced but have not yet been 

commercially collected. This includes 

both agricultural and forestry residues. 

Agricultural residues are expected to 

play an important role early on in the 

development of the cellulosic ethanol 

industry due to the fact that they are 

already being grown. Agricultural crop 

residues are biomass that remains in the 

field after the harvest of agricultural 

crops. The most common residue types 

include corn stover (the stalks, leaves, 

and/or cobs), straw from wheat, rice, 

barley, or oats, and bagasse from 

sugarcane. The eight leading U.S. crops 

produce more than 500 million tons of 

residues each year, although only a 

fraction can be used for fuel and/or 

energy production due to sustainability 

and conservation constraints.97 Crop 

residues can be found all over the 

United States, but are primarily 

concentrated in the Midwest since corn 

stover accounts for half of all available 

agricultural residues. 

Agricultural residues play an 

important role in maintaining and 

improving soil quality, protecting the 

soil surface from water and wind 

erosion, helping to maintain nutrient 

levels, and protecting water quality. 

Thus, collection and removal of 

agricultural residues must take into 

account concerns about the potential for 

increased erosion, reduced crop 

productivity, depletion of soil carbon 

and nutrients, and water pollution. 

Sustainable removal rates for 

agricultural residues have been 

estimated in various studies, many 

showing tremendous variability due to 

local differences in soil and erosion 

conditions, soil type, landscape (slope), 

tillage practices, crop rotation 

managements, and the use of cover 

crops. One of the most recent studies by 

top experts in the field showed that 

under current rotation and tillage 

practices, about 30% of stover (about 59 

million metric tons) produced in the 

U.S. could be collected, taking into 

consideration erosion, soil moisture 

concerns, and nutrient replacement 

costs.98 The same study showed that if 

farmers chose to convert to no-till corn 

management and total stover production 

did not change, then approximately 

50% of stover (100 million metric tons) 

could be collected without causing 

erosion to exceed the tolerable soil loss. 

This study, however, did not consider 

possible soil carbon loss which other 

studies indicate may be a greater 

constraint to environmentally 

sustainable feedstock harvest than that 

needed to control water and wind 

erosion.99 Experts agree that additional 

studies are needed to further evaluate 

how soil carbon and other factors affect 

sustainable removal rates. Despite 

unclear guidelines for sustainable 

removal rates due to the uncertainties 

explained above, our agricultural 

modeling analysis assumes that 0% of 

stover is removable for conventional 

tilled lands, 35% of stover is removable 

for conservation tilled lands, and 50% 

is removable for no-till lands. In general, 

these removal guidelines are 

appropriate only for the Midwest, where 

the majority of corn is currently grown. 

As already noted, removal rates will 

vary within regions due to local 

differences. Given the current 

understanding of sustainable removal 

rates, we believe that such assumptions 

are reasonably justified. We invite 

comment on these assumptions. Based 

on our research we also note that 

residue maintenance requirements for 

the amount of biomass that must remain 

on the land to ensure soil quality is 

another approach for modeling 

sustainable residue collection 

quantities, therefore we also invite 

comment on this approach. This 

approach would likely be more accurate 

for all landscapes as site specific 

conditions such as soil type, 

topography, etc. could be taken into 

account. This would prevent site 

specific soil erosion and soil quality 

concerns that would inevitably exist 

when using average values for residue 

removal rates across all soils and 

landscapes. At the time of our analyses 

we had limited data on which to 

accurately apply this approach and 

therefore assumed the removal 

guidelines based on tillage practices. 

Refer to the Section 1.1 of the DRIA for 

more discussion on sustainable removal 

rates. 

Some of the challenges of relying on 

agricultural residues to produce biofuels 

include the development of the 

technology and infrastructure for the 

harvesting of biomass crops. For 

example, it may be possible to reduce 

costs by harvesting the corn stover at the 

same time that the corn is harvested, in 

a single pass operation, as opposed to 

two separate harvests. In addition, 

because agricultural residues are usually 

harvested only one time per year, but 

cellulosic ethanol plants must receive 

the feedstock throughout the year, 

agricultural residues would likely need 

to be stored at a secondary storage 

facility. The transportation and storage 

issues and costs associated with this 

secondary storage will add additional 

costs to using agricultural residue as 

cellulosic plant feedstock. These 

significant transportation and storage 

issues need to be resolved and the 

infrastructure built before agricultural 

24994 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

100Assuming 94 gal/dry ton ethanol conversion 

yield for corn stover in 2022. 

101Bagasse is a byproduct of sugarcane crushing 

and not technically an agricultural residue. Sweet 

sorghum pulp is also a byproduct of sweet sorghum 

processing. We have included it under this heading 

for simplification due to sugarcane being an 

agricultural feedstock. 

102Smith, W. Brad et. al., ‘‘Forest Resources of 

the United States, 2002 General Technical Report 

NC–241,’’ St. Paul, MN: U.S. Dept. of Agriculture, 

Forest Service, North Central Research Station, 

2004. 

103USDA–Forest Service. ‘‘Timber Products 

Output Mapmaker Version 1.0.’’ 2004. 

104 DOE., ‘‘Breaking the Biological Barriers to 

Cellulosic Ethanol: A Joint Research Agenda,’’ 2006. 

105Tolbert, V.R., et al., ‘‘Biomass Crop 

Production: Benefits for Soil Quality and Carbon 

Sequestration,’’ March 1999. 

106Lewandowski, I., J. M. O. Scurlock, E. 

Lindvall, and M. Chistou, ‘‘The development and 

current status of perennial rhizomatous grasses as 

energy crops in the U.S. and Europe,’’ Biomass 

Bioenergy 25:335–361, 2003. 

107The Council for Agricultural Science and 

Technology (CAST), ‘‘Biofuel Feedstocks: The Risk 

of Future Invasions,’’ CAST Commentary 

QTA2007–1. November 2007. Accessed at: http:// 

pdf.cast-science.org/websiteUploads/

publicationPDFs/Biofuels%20Commentary%20

Web%20version%20with%20color%20

%207927146.pdf 

108Zeman, N., ‘‘Feedstock: Potential Players,’’ 

Ethanol Producer Magazine, October 2006. 

residues can supply a steady stream of 

feedstock to the biorefinery. We discuss 

these harvesting and storage challenges 

in Section 1.3 of the DRIA. 

Our agricultural modeling (FASOM) 

suggests that corn stover will make up 

the majority of agricultural residues 

used by 2022 to meet the EISA 

cellulosic biofuel standard 

(approximately 83 million dry tons used 

to produce 7.8 billion gallons of 

cellulosic ethanol).100 Smaller 

contributions are expected to come from 

other crop residues, including bagasse 

(1.2 Bgal ethanol) and sweet sorghum 

pulp (0.1 Bgal ethanol).101 At the time 

of this proposal, FASOM was able to 

model agricultural residues but not 

forestry biomass as potential feedstocks. 

As a result, we relied on USDA–Forest 

Service (FS) for information on the 

forestry sector. 

The U.S. has vast amounts of forest 

resources that could potentially provide 

feedstock for the production of 

cellulosic biofuel. One of the major 

sources of woody biomass could come 

from logging residues. The U.S. timber 

industry harvests over 235 million dry 

tons annually and produces large 

volumes of non-merchantable wood and 

residues during the process.102 Logging 

residues are produced in conventional 

harvest operations, forest management 

activities, and clearing operations. In 

2004, these operations generated 

approximately 67 million dry tons/year 

of forest residues that were left 

uncollected at harvest sites.103 Other 

feedstocks include those from other 

removal residues, thinnings from 

timberland, and primary mill residues. 

Harvesting of forestry residue and 

other woody material can be conducted 

throughout the year. Thus, unlike 

agricultural residue which must be 

moved to secondary storage, forest 

material could be ‘‘stored on the 

stump.’’ Avoiding the need for 

secondary storage and the transportation 

costs for moving the feedstock there 

potentially provides a significant cost 

advantage for forest residue over 

agricultural residue. This could allow 

forest residue to be transported from 

further distances away from the 

cellulosic plant compared to 

agricultural residue at the same 

feedstock price. Section 1.1 of the DRIA 

further details some of challenges with 

using forestry biomass as a feedstock. 

EISA does not allow forestry material 

from national forests and virgin forests 

that could be used to produce biofuels 

to count towards the renewable fuels 

requirement under EISA. Therefore, we 

required forestry residue estimates that 

excluded such material. Most recently, 

the USDA–FS provided forestry biomass 

supply curves for various sources (i.e., 

logging residues, other removal 

residues, thinnings from timberland, 

etc.). This information suggested that a 

total of 76 million dry tons of forest 

material could be available for 

producing biofuels (excluding forest 

biomass material contained in national 

forests as required under EISA). 

However, much of the forest material is 

in small pockets of forest which because 

of its regional low density, could not 

help to justify the establishment of a 

cellulosic ethanol plant. After 

conducting our feedstock availability 

analysis, we estimated that 

approximately 44 million dry tons of 

forest material could be used, which 

would make up approximately one 

fourth, or 3.8 billion gallons, of the 16 

billion gallons of cellulosic biofuel 

required to meet EISA. 

iii Dedicated Energy Crops 

While urban waste, agricultural 

residues, and forest residues will likely 

be the first feedstocks used in the 

production of cellulosic biofuel, there 

may be limitations to their use due to 

land availability and sustainable 

removal rates. Energy crops which are 

not yet grown commercially but have 

the potential for high yields and a series 

of environmental benefits could help 

provide additional feedstocks in the 

future. Dedicated energy crops are plant 

species grown specifically as renewable 

fuel feedstocks. Various perennial 

plants have been researched as potential 

dedicated feedstocks. These include 

switchgrass, mixed prairie grasses, 

hybrid poplar, miscanthus, and willow 

trees. 

Perennials have several benefits over 

many major agricultural crops (the 

majority of which are annual plants). 

First, energy crops based on perennial 

species are grown from roots or 

rhizomes that remain in the soil after 

harvests. This reduces annual field 

preparation and fertilization costs. 

Second, perennial crops in temperate 

zones may also have significantly higher 

total biomass yield per unit of land area 

compared to annual species because of 

higher rates of net photosynthetic CO2

fixation into sugars. Third, lower 

fertilizer runoff, lower soil erosion, and 

increased habitat diversity are also 

attributes that make perennial crops 

more attractive than annual crops.104

Finally, energy crops tend to store more 

carbon in the soil compared to 

agricultural crops such as corn.105

The introduction of dedicated energy 

crops could present some potential 

risks, however. Dedicated energy crops 

for cellulosic biofuels can be non-native 

to the region where their production is 

proposed.106 As a result, these species 

may potentially escape cultivation and 

damage surrounding ecosystems.107 In 

addition breeding and genetic 

engineering to increase environmental 

tolerance, increase harvestable biomass 

production, and enhance energy 

conversion may have unexpected 

ecological consequences. To minimize 

such risks, non-native species and nonwild-type native species (i.e. native 

species after genetic modification) 

should be introduced in a responsible 

manner and evaluated carefully in order 

to weigh the potential risks against the 

benefits. 

Currently, an energy crop receiving 

much attention is switchgrass. 

Switchgrass has many qualities that 

make it a prime cellulosic feedstock 

option. However, switchgrass and other 

energy crops are not currently harvested 

on a large scale. Switchgrass would 

likely be grown on a 10-year crop 

rotation basis, with harvest beginning in 

year 1 or 2, depending on location. 

Because switchgrass and other 

dedicated energy crops would not be 

harvested annually, there will be some 

economic challenges in terms of price 

forecasting and contracts. Accordingly, 

10- to 15-year arrangements may be 

needed to stabilize the market for energy 

crops.108 Despite these challenges, 

dedicated energy crops are still 

projected to be needed in 2022 in order 

to meet the aggressive goal of 16 Bgal of 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24995 

109Campbell, J.E. at al., ‘‘The global potential of 

bioenergy on abandoned agriculture lands,’’ 

Environ. Sci. Technology, 2008. 

110Charles, Dan; ‘‘The CRP: Paying Farmers not 

to Farm,’’ National Public Radio, May 5, 2008. 

111Farm Service Agency, ‘‘Conservation Reserve 

Program, Summary and Enrollment Statistics 

FY2006,’’ May 2007. 

112Assuming 16 Bgal cellulosic biofuel total, 2.2 

Bgal from Urban Waste, and 3.8 Bgal from Forestry 

Biomass; 10 Bgal of cellulosic biofuel for ag 

residues and/or energy crops would be needed. 

113Beside the economic incentive of a farmer 

payment to keep land in CRP, local environmental 

interests may also fight to maintain CRP land for 

wildlife preservation. Also, we did not know what 

portion of the CRP is wetlands which likely could 

not support harvesting equipment. 

114Biomass Research and Development Initiative 

(BR&DI), ‘‘Increasing Feedstock Production for 

Biofuels: Economic Drivers, Environmental 

Implications, and the Role of Research,’’ http:// 

www.brdisolutions.com December 2008. 115NASS database. http://www.nass.usda.gov/. 

cellulosic biofuel by 2022 as outlined in 

EISA. 

Since energy crops are not being 

grown today to make fuels, their 

production and use depends on the 

development of a successful strategy. 

One issue is that if they were to be 

grown on farmland currently used to 

grow crops, the growth of switchgrass 

would have an opportunity cost 

associated with the loss of agricultural 

production. For this reason, energy 

crops may instead be grown on more 

marginal farm land such as fallow 

farmland and farmland which has been 

converted over to prairie grass. A study 

by Stanford and the Carnegie Institution 

found that 58 million hectares (145 

million acres) of abandoned farmland 

would potentially be available for 

growing energy crops here in the U.S.109

However, they also concluded that this 

land is marginal in quality and thus the 

production per acre would be much 

lower compared to prime farm land. 

Additionally, a substantial amount of 

this abandoned farm land is a part of the 

Conservation Reserve Program (CRP). 

The CRP is the U.S. Department of 

Agriculture’s voluntary program that 

was established by the Food Security 

Act of 1985 to provide farmers with a 

dependable source of income, reduce 

erosion on unused farmland, and serve 

to preserve wildlife and water 

quality.110 A large portion of the 36 

million acres in the CRP land is 

currently planted with switchgrass and 

mixed prairie grasses.111 However, the 

2008 Farm Bill capped the number of 

CRP acres at 32 million acres for 2010– 

2012, and we expect that some of the 

CRP acres that are not re-enrolled will 

go into crop production. While it may 

be possible to use some of the CRP acres 

to produce biofuels from switchgrass 

and prairie grass, the potential loss of 

the wildlife habitat and water quality 

benefits of CRP land would have to be 

weighed against the potential use for 

this land for growing energy crops. Also, 

a significant portion of the CRP land is 

wetlands and likely could not be used 

for growing energy crops without 

impacting water quality and wildlife. 

In addition to estimating the extent 

that agricultural residues might 

contribute to cellulosic ethanol 

production, FASOM also estimated the 

contribution that energy crops might 

provide.112 FASOM covers all cropland 

and pastureland in production in the 48 

conterminous United States, however it 

does not contain all categories of 

grassland and rangeland captured in 

USDA’s Major Land Use data sets. 

Therefore, it is possible there is land 

appropriate for growing dedicated 

energy crops that is not currently 

modeled in FASOM. Furthermore, we 

constrained FASOM to be consistent 

with the 2008 Farm Bill and assumed 32 

million acres would stay in CRP.113

These constraints on land availability 

may have contributed to the model 

choosing a substantial amount of 

agricultural residues mostly as corn 

stover and a relatively small portion of 

energy crops as being economically 

viable feedstocks. The use of other 

models, such as USDA’s Regional 

Environment and Agriculture 

Programming (REAP) model and 

University of Tennessee’s POLYSYS 

model, have shown that the use of 

energy crops in order to meet EISA may 

be more significant than our current 

FASOM modeling results.114 As such, 

we plan to revisit these land availability 

assumptions in order to arrive at a more 

consistent basis for the FRM. We request 

comment on these assumptions, in 

addition to all the cellulosic yield 

assumptions that are contained in DRIA 

Chapter 1. 

iv. Summary of Cellulosic Feedstocks 

for 2022 

Table V.B.2–4 summarizes our 

internal estimate of cellulosic feedstocks 

and their corresponding volume 

contribution to 16 billion gallons 

cellulosic biofuel by 2022 for the 

purposes of our impacts assessment. 

TABLE V.B.2–4—CELLULOSIC FEEDSTOCKS ASSUMED TO MEET EISA IN

2022 

Feedstock Volume 

(Bgal) 

Agricultural Residues .................... 9.1 

Corn Stover ........................... 7.8 

Sugarcane Bagasse .............. 1.2 

Sweet Sorghum Pulp ............ 0.1 

Forestry Biomass .......................... 3.8 

Urban Waste ................................. 2.2 

Dedicated Energy Crops 

(Switchgrass) ............................ 0.9 

Total ............................... 16.0 

v. Cellulosic Plant Siting 

Future cellulosic biofuel plant siting 

was based on the types of feedstocks 

that would be most economical as 

shown in Table V.B.2–4, above. As 

cellulosic biofuel refineries will likely 

be located close to biomass resources in 

order to take advantage of lower 

transportation costs, we’ve assessed the 

potential areas in the U.S. that grow the 

various feedstocks chosen. To do this, 

we used data on harvested acres by 

county for crops that are currently 

grown today, such as corn stover and 

sugarcane (for bagasse).115 In some 

cases, crops are not currently grown, but 

have the potential to replace other crops 

or pastureland (e.g. dedicated energy 

crops). We used the output from our 

economic modeling (FASOM) to help us 

determine which types of land are likely 

to be replaced by newly grown crops. 

For forestry biomass, USDA-Forestry 

Service provided supply curve data by 

county showing the available tons 

produced. Urban waste (MSW wood, 

paper, and C&D debris) was estimated to 

be located near large population centers. 

Using feedstock availability data by 

county/city, we located potential 

cellulosic sites across the U.S. that 

could justify the construction of a 

cellulosic plant facility. For more details 

on this analysis, refer to Section 1.5 of 

the DRIA. Table V.B.2–5 shows the 

volume of cellulosic facilities by 

feedstock by state projected for 2022. 

The total volumes given in Table V.B.2– 

5 match the total volumes given in 

Table V.B.2–4 within a couple hundred 

million gallons. As these differences are 

relatively small, we believe the 

cellulosic facilities sited are a good 

estimate of potential locations. 

24996 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

116USDA, WGA, Bioenergy Strategic Assessment 

project findings upcoming as noted in report WGA. 

Transportation Fuels for the Future Biofuels: Part I. 

2008. 

117F.O. Licht., ‘‘World Ethanol Markets: The 

Outlook to 2015’’, 2006, pg. 21. 

118Renewable Fuels Association (RFA), ‘‘2007 

World Fuel Ethanol Production,’’ 

http://www.ethanolrfa.org/industry/statistics/#E, 

March 31, 2009. 

TABLE V.B.2–5—PROJECTED CELLULOSIC ETHANOL VOLUMES BY STATE

[Million gallons in 2022] 

State Total 

volume 

Agricultural 

residue 

volume 

Energy 

crop 

volume 

Urban 

waste 

volume 

Forestry 

volume 

Alabama ....................................................................................................... 532 0 0 140 392 

Arkansas ...................................................................................................... 298 0 0 0 298 

California ...................................................................................................... 450 0 0 221 229

Colorado ....................................................................................................... 28 0 0 28 0 

Florida .......................................................................................................... 421 390 0 31 0

Georgia ........................................................................................................ 437 0 0 67 370 

Illinois ........................................................................................................... 1,525 1,270 0 198 58 

Indiana ......................................................................................................... 1,109 948 0 101 60 

Iowa .............................................................................................................. 1,697 1,635 0 32 30 

Kansas ......................................................................................................... 310 250 0 29 32 

Kentucky ...................................................................................................... 70 70 0 0 0 

Louisiana ...................................................................................................... 1,001 590 0 103 308 

Maine ........................................................................................................... 191 0 0 2 189 

Michigan ....................................................................................................... 505 283 0 171 51

Minnesota ..................................................................................................... 876 750 0 50 76 

Mississippi .................................................................................................... 214 0 0 22 192 

Missouri ........................................................................................................ 654 504 0 78 72

Montana ....................................................................................................... 92 0 0 9 83 

Nebraska ...................................................................................................... 956 851 0 31 75 

Nevada ......................................................................................................... 17 0 0 17 0 

New Hampshire ........................................................................................... 171 0 35 29 107 

New York ..................................................................................................... 72 0 0 72 0 

North Carolina .............................................................................................. 315 0 0 98 217 

Ohio .............................................................................................................. 598 410 0 156 32 

Oklahoma ..................................................................................................... 793 0 777 0 16 

Oregon ......................................................................................................... 244 0 0 44 200 

Pennsylvania ................................................................................................ 42 0 0 42 0 

South Carolina ............................................................................................. 213 0 0 57 156 

South Dakota ............................................................................................... 434 350 0 6 78 

Tennessee ................................................................................................... 97 0 0 19 78 

Texas ........................................................................................................... 576 300 0 131 145 

Virginia ......................................................................................................... 197 0 0 95 102

Washington .................................................................................................. 175 0 0 17 158 

West Virginia ................................................................................................ 149 0 101 0 48 

Wisconsin ..................................................................................................... 581 432 0 43 106 

Total Volume ......................................................................................... 16,039 9,034 913 2,139 3,955 

It is important to note, however, that 

there are many more factors other than 

feedstock availability to consider when 

eventually siting a plant. We have not 

taken into account, for example, water 

constraints, availability of permits, and 

sufficient personnel for specific 

locations. As many of the corn stover 

facilities are projected to be located 

close to corn starch facilities, there is 

the potential for competition for clean 

water supplies. Therefore, as more and 

more facilities draw on limited 

resources, it may become apparent that 

various locations are infeasible. 

Nevertheless, our plant siting analysis 

provides a reasonable approximation for 

analysis purposes since it is not 

intended to predict precisely where 

actual plants will be located. Other 

work is currently being done that will 

help address some of these issues, but 

at the time of this proposal, was not yet 

available.116

As we are projecting the location of 

cellulosic plants in 2022, it is important 

to keep in mind the various 

uncertainties in the analysis. For 

example, future analyses could 

determine better recommendations for 

sustainable removal rates. In the case 

where lower removal rates are 

recommended, agricultural residues 

may be more limited and could require 

more growth in dedicated energy crops. 

Also, the feedstocks could be processed 

in the field to a liquid by a pyrolysis 

process, facilitating the ability to ship 

the preprocessed biomass to plants 

located further away from the feedstock 

source. Given the information we have 

to date, we believe our projected 

locations for cellulosic facilities 

represent a reasonable forecast for 

estimating the impacts of this rule. 

3. Imported Ethanol 

a. Historic World Ethanol Production 

and Consumption 

Although ethanol can be used for 

multiple purposes (fuel, industrial, and 

beverage), fuel ethanol is by far the 

largest market, accounting for about 

two-thirds of the total world ethanol 

consumed. According to forecasts, fuel 

ethanol might even exceed 80% of the 

market share by the end of the 

decade.117 In 2008, the top three fuel 

ethanol producers were the U.S., Brazil, 

and the European Union (EU), 

producing 9.0, 6.5, and 0.7 billion 

gallons, respectively.118 Other countries 

that have produced ethanol include 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24997 

119 Ibid. 

120UNICA, ‘‘Sugarcane Industry in Brazil: 

Ethanol Sugar, Bioelectricity’’ Brochure, 2008. 

121European Bioethanol Fuel Association (eBio), 

‘‘The EU Market: Production and Consumption,’’ 

http://www.ebio.org/EUmarket.php, March 31, 

2009. 

122 Values given report USITC and RFA data, 

however, EIA reports slightly lower numbers prior 

to 2004. 123USITC and EIA import data reported. 

124Agra FNP, ‘‘Sugar and Ethanol in Brazil: A 

Study of the Brazilian Sugar Cane, Sugar and 

Ethanol Industries,’’ 2007. 

125CGEE, ABDI, Unicamp, and NIPE, Scaling Up 

the Ethanol Program in Brazil, n.d. as quoted in 

Rothkopf, Garten, ‘‘A Blueprint for Green Energy in 

the Americas,’’ 2006. 

126Rothkopf, Garten, ‘‘A Blueprint for Green 

Energy in the Americas,’’ 2006. 

127 Ibid. 

128 Ibid. 

China, Canada, Thailand, Colombia, and 

India. 

Consumption of fuel ethanol, like 

production, is also dominated by the 

United States and Brazil. The U.S. 

dominates world fuel ethanol 

consumption, with 9.6 billion gallons 

consumed in 2008 (domestic production 

plus imports).119 Brazil is second in 

consumption, with about 4.9 billion 

gallons projected to be consumed in 

2007/2008.120 The EU is also a 

significant consumer of ethanol; 

however, consumption for the EU 

countries was only approximately 0.7 

billion gallons in 2007.121

b. Historic/Current Domestic Imports 

Ethanol imports have traditionally 

played a relatively small role in the U.S. 

transportation fuel market due to 

historically low crude prices and the 

tariff on imported ethanol. While low 

crude prices made it difficult for both 

domestic and imported ethanol to 

compete with gasoline, the addition of 

the federal excise tax credit made it 

possible for domestic ethanol to be 

economically competitive. 

Between 2000 and 2003, the total 

volume of fuel ethanol imports into the 

United States remained relatively stable 

at 46–68 million gallons.122 During this 

period of time, mostly Brazilian-based 

ethanol entered the U.S. primarily 

through the Caribbean Basin Initiative 

(CBI) countries where it could avoid the 

tariff. From 2004–2005, with rising 

crude oil prices, most estimates show 

U.S. fuel ethanol imports increased 

slightly to 135–164 million gallons, or 

about 4% of the total U.S. fuel ethanol 

consumption (3.5 to 4.0 billion gallons). 

The volume of imports rose 

dramatically in 2006 to 654–720 million 

gallons, or about 13% of the 2006 total 

ethanol consumption of 5.4 billion 

gallons. The largest volume of imports 

in 2006 was from direct Brazilian 

imports. This increase in ethanol 

imports was mainly due to the 

withdrawal of MTBE from the fuel pool 

which increased the price of ethanol. 

MTBE was used in gasoline to fulfill the 

oxygenate requirements set by Congress 

in the 1990 Clean Air Act Amendments. 

EPAct further accelerated the 

withdrawal of MTBE because gasoline 

marketers were no longer required to 

use an oxygenate and gasoline marketers 

did not receive the MTBE liability 

protection that they had petitioned for. 

Refiners responded by removing MTBE 

and replacing its use with ethanol. As 

a result, the demand for ethanol 

increased at unprecedented rates as 

most refiners replaced MTBE with 

ethanol. The dramatic increase in crude 

oil costs at this time also made ethanol 

more economical by comparison. 

By the end of 2006, almost all MTBE 

was phased out of gasoline. However, 

crude oil prices remained high, allowing 

ethanol imports to the U.S. to remain 

economical in comparison to the past. 

Although not as high as the volume of 

ethanol imported in 2006, the U.S. 

continued to import ethanol in 2007 

(425–450 million gallons). In 2008, the 

U.S. imported 519–556 million 

gallons.123 As the data show, the 

volume of imported ethanol can 

fluctuate greatly. By looking at historical 

import data it is difficult to project the 

potential volume of future imports to 

the U.S. Rather, it is necessary to assess 

future import potential by analyzing the 

major players for foreign biofuels 

production and consumption. 

c. Projected Domestic Imports 

In our assessment of foreign ethanol 

production and consumption, we 

analyzed the following countries or 

group of countries: Brazil, the EU, 

Japan, India, and China. Our analyses 

indicate that Brazil would likely be the 

only nation able to supply any 

meaningful amount of ethanol to the 

U.S. in the future. Depending on 

whether the mandates and goals of the 

EU, Japan, India, and China are enacted 

or met in the future, it is likely that this 

group of countries would consume any 

growth in their own production and be 

net importers of ethanol, thus 

competing with the U.S. for Brazilian 

ethanol exports. 

Brazil is expected to supply the 

majority of future ethanol demand and 

to expand their capacity for several 

reasons. First, Brazil has over 30 years 

experience in developing the research 

and technologies for producing 

sugarcane ethanol. As a result, 

Brazilians have been able to improve 

agricultural and conversion processes so 

that sugarcane ethanol is currently the 

least costly method for producing 

biofuels. See Section VIII for further 

discussion on the production costs for 

sugarcane ethanol. 

Second, it is believed that domestic 

demand for ethanol in Brazil will begin 

to slow as most of the national fleet of 

vehicles will have transitioned to flexfuel within the next few years.124 Thus, 

as domestic demand begins to level off, 

some experts see a significant 

possibility that exports will become 

more relevant in market share terms. 

Lastly, Brazil has large land areas for 

potential expansion for sugarcane. A 

study commissioned by the Brazilian 

government produced an analysis in 

which Brazil’s arable land was 

evaluated for its suitability for cane.125

Setting aside areas protected by 

environmental regulations and those 

with a slope greater than 12% (those not 

suitable for mechanized farming), 

tripling ethanol production (a goal set 

by the Brazilian government by 2020) 

would require only an additional 14 

million acres. This additional acreage 

would only be about 2% of suitable land 

for sugarcane production. Refer to 

Section 1.5 of the DRIA for more details. 

Although Brazil is in an excellent 

position to help meet the growing global 

demand for ethanol, several constraints 

could limit the expansion of ethanol 

production. As Brazil’s government has 

adopted plans to meet global demand by 

tripling production by 2020,126 this 

would mean a total capacity of about 

12.7 billion gallons, to be achieved 

through a combination of efficiency 

gains, greenfield projects, and 

infrastructure expansions. Estimates for 

the investment required tend to range 

from $2 to $4 billion a year.127 In 

addition, Brazil will need to improve its 

current ethanol infrastructure (i.e. 

improvements in power, transportation, 

storage, distribution logistics, and 

communications). It is estimated that 

Brazil will need to invest $1 billion each 

year for the next 15 years in 

infrastructure to keep pace with 

capacity expansion and export 

demand.128 Refer to Section 1.5 of the 

DRIA for further details on the 

improvements needed for Brazil to 

increase ethanol production capacity. 

Due to uncertainties in the future 

demand for ethanol domestically and 

internationally as well as uncertainties 

in the actual investments made in the 

Brazilian ethanol industry, there 

appears to be a wide range of Brazilian 

production and domestic consumption 

estimates. The most current and 

complete estimates indicate that total 

24998 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

129EPE, ‘‘Plano Nacional de Energia 2030,’’ 

Presentation from Mauricio Tolmasquim, 2007. 

130UNICA, ‘‘Sugarcane Industry in Brazil: 

Ethanol, Sugar, Bioelectricity,’’ 2008. 

131USEPA International Visitors Program Meeting 

October 30, 2007, correspondence with Mr. 

Rodrigues, Technical Director from UNICA Sao 

Paulo Sugarcane Agro-industry Union, stated 

approximately 3.7 billion gallons probable by 2017/ 

2020; Consistent with brochure ‘‘Sugarcane 

Industry in Brazil: Ethanol Sugar, Bioelectricity’’ 

from UNICA (3.25 Bgal export in 2015 and 4.15 

Bgal export in 2020). 

132Other preferential trade agreements include 

the North American Free Trade Agreement 

(NAFTA) which permits tariff-free ethanol imports 

from Canada and Mexico and the Andean Trade 

Promotion and Drug Eradication Act (ATPDEA) 

which allows the countries of Columbia, Ecuador, 

Bolivia, and Peru to import ethanol duty-free. 

Currently, these countries export or produce 

relatively small amounts of ethanol, and thus we 

have not assumed that the U.S. will receive any 

substantial amounts from these countries in the 

future for our analyses. 133Rapoza, Kenneth, ‘‘UPDATE: Tax Loophole 

Helps US Import Ethanol ‘Duty Free’—ED&F,’’ INO 

News, Dow Jones Newswires, March 2008. http:// 

news.ino.com/. 134Peter Rhode, ‘‘Senate Finance May Take Up 

Drawback Loophole As Part of Energy Bill,’’ 

EnergyWashington Week, April 18, 2007. As sited 

in Yacobucci, Brent, ‘‘Ethanol Imports and the 

Caribbean Basin Initiative,’’ CRS Report for 

Congress, Order Code RS21930, Updated March 18, 

2008. 135Perkins, Jerry, ‘‘BRAZIL: Loophole Hurt U.S. 

Ethanol Prices,’’ DesMoinesRegister.com, October 

18, 2007. 

136Public Law Version 6124 of the Farm Bill. 

2008. http://www.usda.gov/documents/ 

Bill_6124.pdf. 137Lundell, Drake, ‘‘Brazilian Ethanol Export 

Surge to End; U.S. Customs Loophole Closed Oct. 

1,’’ Ethanol and Biodiesel News, Issue 45, 

November 4, 2008. 138Source: EIA data on company-level imports 

(http://www.eia.doe.gov/oil_gas/petroleum/ 

data_publications/company_level_imports/ 

cli_historical.html). 

Brazilian ethanol exports will likely 

reach 3.8–4.2 billion gallons by 

2022.129 130 131 As this volume of ethanol 

export is available to countries around 

the world, only a portion of this will be 

available exclusively to the United 

States. If the balance of the EISA 

advanced biofuel requirement not met 

with cellulosic biofuel and biomassbased diesel were to be met with 

imported sugarcane ethanol alone, it 

would require 3.2 billion gallons (see 

Table V.A.2–1), or approximately 80% 

of total Brazilian ethanol export 

estimates. 

The amount of Brazilian ethanol 

available for shipment to the U.S. will 

be dependent on the biofuels mandates 

and goals set by other foreign countries 

(i.e., the EU, Japan, India, and China) in 

addition to U.S. policies to promote the 

use of renewable fuels. Our estimates 

show that there could be a potential 

demand for imported ethanol of 4.6– 

14.6 billion gallons by 2020/2022 from 

these countries. This is due to the fact 

that some countries are unable to 

produce large volumes of ethanol 

because of land constraints or low 

production capacity. As such, foreign 

countries may have limited domestic 

biofuel production capability and may 

therefore require importation of biofuels 

in order to meet their mandates and 

goals. Refer to Section 1.5 of the DRIA 

for further details. Therefore, if other 

foreign country mandates and goals are 

to be met, then Brazil may need to either 

increase production much more than its 

government projects or export less 

ethanol to the U.S. This suggests that 

the U.S. may be competing for Brazilian 

ethanol exports if supplies are limited 

in the future. For our analysis we 

assumed that the U.S. would consume 

the majority of Brazilian exports (i.e. 

80% of export estimates in 2022). This 

is aggressive, yet within the bounds of 

reason, therefore, we have made this 

simplifying assumption for the purposes 

of further analysis. We seek comment on 

the legitimacy of this assumption given 

the ethanol export deals and 

commitments that Brazil has made or 

may potentially make with other nations 

in the future. 

Generally speaking, Brazilian ethanol 

exporters will seek routes to countries 

with the lowest transportation costs, 

taxes, and tariffs. With respect to the 

U.S., the most likely route is through the 

Caribbean Basin Initiative (CBI).132

Brazilian ethanol entering the U.S. 

through the CBI countries is not 

currently subject to the 54 cent 

imported ethanol tariff and yet receives 

the 45 cent ethanol blender tax subsidy. 

Due to the economic incentive of 

transporting ethanol through the CBI, 

we expect the majority of the tariff rate 

quota (TRQ) to be met or exceeded, 

perhaps 90% or more. The TRQ is set 

each year as 7% of the total domestic 

ethanol consumed in the prior year. If 

we assume that 90% of the TRQ is met 

and that total domestic ethanol (corn 

and cellulosic ethanol) consumed in the 

prior year was 28.5 Bgal, then 

approximately 1.8 Bgal of ethanol could 

enter the U.S. through CBI countries. 

The rest of the Brazilian ethanol exports 

not entering the CBI will compete on the 

open market with the rest of the world 

demanding some portion of direct 

Brazilian ethanol. We calculated the 

amount of direct Brazilian ethanol 

exports in 2022 to the U.S. as the total 

imported ethanol required (3.14 billion 

gallons) to meet the RFS2 volume 

requirements subtracted by imported 

ethanol from CBI countries (1.8 billion 

gallons), or equal to 1.34 billion gallons. 

In the past, companies have also 

avoided the ethanol import tariff 

through a duty drawback.133 The 

drawback is a loophole in the tax rules 

which allowed companies to import 

ethanol and then receive a rebate on 

taxes paid on the ethanol when jet fuel 

is sold for export within three years. 

The drawback considered ethanol and 

jet fuel as similar commodities (finished 

petroleum derivatives).134 135 Most 

recently, however, Senate 

Representative Charles Grassley from 

Iowa included a provision into the Farm 

Bill of 2008 that ended such refunds. 

The provision states that ‘‘any duty paid 

under subheading 9901.00.50 of the 

Harmonized Tariff Schedule of the 

United States on imports of ethyl 

alcohol or a mixture of ethyl alcohol 

may not be refunded if the exported 

article upon which a drawback claim is 

based does not contain ethyl alcohol or 

a mixture of ethyl alcohol.’’ 136 The 

provision is effective on or after October 

1, 2008 and companies have until 

October 1, 2010 to apply for a duty 

drawback on prior transactions. With 

the loophole closed, it is anticipated 

that there may be less ethanol directly 

exported from Brazil in the future.137

For our distribution and air quality 

analyses, we had to make a 

determination as to where the projected 

imported ethanol would likely enter the 

United States. To do so, we started by 

looking at 2006 ethanol import data and 

made assumptions as to which countries 

would likely contribute to the CBI 

ethanol volumes in Table V.B.3–1, and 

to what extent.138 We estimated that, on 

average, in future years, 30% would 

come from Jamaica, 20% each would 

come from El Salvador and Costa Rica, 

and 15% each would originate from 

Trinidad & Tobago and the Virgin 

Islands. Even though to date there have 

not been a lot of ethanol imports from 

the Virgin Islands, we believe that they 

could become a comparable importer to 

Trinidad & Tobago in the future under 

the proposed RFS2 program. 

From there, we looked at 2006–2007 

import data and estimated the general 

destination of Brazilian ethanol and the 

five contributing CBI countries’ 

domestic imports. Based on these 

countries’ geographic locations and 

import histories, we estimated that in 

2022 about 75% of the ethanol would be 

imported to the East and Gulf Coasts 

and the remainder would go to the West 

Coast and Hawaii. To estimate import 

locations, we considered coastal port 

cities that had received ethanol or 

finished gasoline imports in 2006 and 

distributed the ethanol accordingly 

based on ethanol demand. For more 

information on this analysis, refer to 

Section 1.5 of the DRIA. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 24999 

139See Section 1515 of the Energy Policy Act of 

2005. More discussion of the definitions of 

biodiesel and renewable diesel are given in the 

preamble of the Renewable Fuel Standard 

rulemaking, Section III.B.2, as published in the 

Federal Register Vol. 72, No. 83, p. 23917. 140For more detailed discussion of the definition 

of coprocessing and its implications for compliance 

with EISA, see Section III.B.1 of this preamble. 

141Figures here were taken from National 

Biodiesel Board fact sheet dated September 29, 

2008 (http://biodiesel.org/pdf_files/fuelfactsheets/ 

Producers%20Map%20-%20existing.pdf). This 

information was current at the time these analyses 

were being done. More recent data maintained by 

Biodiesel Magazine suggests that by April 2009 the 

industry had contracted to approximately 137 

plants with aggregate capacity of 2.3 billion gal/yr 

(see http://www.biodieselmagazine.com/plantlist.jsp). 

142Capital figures derived from USDA production 

cost models. A publication describing USDA 

modeling of biodiesel production costs can be 

found in Bioresource Technology 97(2006) 671–8. 

143Capacity data taken from National Biodiesel 

Board. Production figures taken from F.O. Licht 

World Ethanol and Biofuels Report, vol. 6, no. 11, 

p S271, except 2008, which is an estimate taken 

from National Biodiesel Board (http:// 

www.biodiesel.org/pdf_files/fuelfactsheets/

Production_graph_slide.pdf). 

4. Biodiesel & Renewable Diesel 

Biodiesel and renewable diesel are 

replacements for petroleum diesel that 

are made from plant or animal fats. 

Biodiesel consists of fatty acid methyl 

esters (FAME) and can be used in lowconcentration blends in most types of 

diesel engines and other combustion 

equipment with no modifications. The 

term renewable diesel covers fuels made 

by hydrotreating plant or animal fats in 

processes similar to those used in 

refining petroleum. Renewable diesel is 

chemically analogous to blendstocks 

already used in petroleum diesel, thus 

its use can be transparent and its blend 

level essentially unlimited. The goal of 

both biodiesel and renewable diesel 

conversion processes is to change the 

properties of a variety of feedstocks to 

more closely match those of petroleum 

diesel (such as its density, viscosity, and 

energy content) for which the engines 

and distribution system have been 

designed. Both processes can produce 

suitable fuels from biogenic sources, 

though we believe some feedstocks lend 

themselves better to one process or the 

other. The definition of biodiesel given 

in applicable regulations is sufficiently 

broad to be inclusive of both fuels.139

However, the EISA stipulates that 

renewable diesel that is co-processed 

with petroleum diesel cannot be 

counted as ‘‘biomass-based diesel’’ for 

purposes of complying with its volume 

mandates.140

In general, plant and animal oils are 

valuable commodities with many uses 

other than transportation fuel. Therefore 

we expect the primary limiting factor in 

the supply of both biodiesel and 

renewable diesel to be feedstock 

availability and price. Expansion of 

their market volumes is dependent on 

being able to compete on price with the 

petroleum diesel they are displacing, 

which will depend largely on 

continuation of current subsidies and 

other incentives. 

Other biomass-based diesel fuel 

plants are either already built or being 

considered for construction. Cello 

Energy has already started up a 20 

million gallon per year catalytic 

depolymerization plant that is 

producing diesel fuel from cellulose and 

other feedstocks, and Cello intends on 

building several 50 million gallon per 

year plants to be started up in 2010. 

Also, numerous other companies are 

planning on building biomass to liquids 

(BTL) plants that produce diesel fuel 

through the syngas and Fischer Tropsch 

pathway. However, for our analysis for 

this proposed rulemaking, we did not 

project that biomass-based diesel fuel 

would be produced from these 

processes. 

a. Historic and Projected Production 

i. Biodiesel 

As of September 2008, the aggregate 

production capacity of biodiesel plants 

in the U.S. was estimated at 2.6 billion 

gallons per year across approximately 

176 facilities.141 Biodiesel plants exist 

in nearly all states, with the largest 

density of plants in the Midwest and 

Southeast where agricultural feedstocks 

are most plentiful. 

Table V.B.4–1 gives U.S. biodiesel 

production capacity, sales, and capacity 

utilization in recent years. The figures 

suggest that the industry has grown out 

of proportion with actual biodiesel 

demand. Reasons for this include 

various state incentives to build plants, 

along with state and federal incentives 

to blend biodiesel, which have given 

rise to an optimistic industry outlook 

over the past several years. Since the 

cost of capital is relatively low for the 

biodiesel production process (typically 

four to six percent of the total per-gallon 

cost), this industry developed a more 

grassroots profile in comparison to the 

ethanol industry, and, with median size 

less than 10 million gallons/yr, consists 

of a large number of small plants.142

These small plants, with relatively low 

operating costs other than feedstock, 

have generally been able to survive 

producing below their nameplate 

capacities. 

TABLE V.B.4–1—U.S. BIODIESEL CAPACITY AND PRODUCTION VOLUMES

[Million gallons] 143

Year Capacity Production Utilization 

(percent) 

2003 ............................................................................................................................................. 150 21 14% 

2004 ............................................................................................................................................. 245 36 15 

2005 ............................................................................................................................................. 395 115 29 

2006 ............................................................................................................................................. 792 241 30 

2007 ............................................................................................................................................. 1,809 499 28 

2008 ............................................................................................................................................. 2,610 700 27 

Some of this industry capacity may 

not be dedicated specifically to fuel 

production, instead being used to make 

oleochemical feedstocks for further 

conversion into products such as 

surfactants, lubricants, and soaps. These 

products do not show up in renewable 

fuel sales figures. 

In 2004–5, demand for biodiesel grew 

rapidly, but the trend of increasing 

capacity utilization was quickly 

overwhelmed by additional plant starts. 

Since then, high commodity prices 

followed by reduced demand for 

transportation fuel have caused 

additional economic strain beyond the 

overcapacity situation. According to a 

survey conducted by Biodiesel 

Magazine staff, more than 1 in 5 plants 

were already idle or defunct as of late 

2007 (though this likely varies by 

25000 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

144 Derived from figures published in Biodiesel 

Magazine, May 2008, p. 39. 

145Staff-level communication with National 

Biodiesel Board (April 2008). 

146 Information on state incentives was taken from 

U.S. Department of Energy Web site, accessed July 

30, 2008, at http://www.eere.energy.gov/afdc/fuels/ 

biodiesel_laws.html. Information on feedstock and 

BQ–9000 status was taken from Biodiesel Board fact 

sheet, accessed July 30, 2008, at http:// 

biodiesel.org/pdf_files/fuelfactsheets/

Producers%20Map%20-%20existing.pdf. 

147 Industry data for 2008 taken from National 

Biodiesel Board fact sheets at http:// 

www.biodiesel.org/buyingbiodiesel/

producers_marketers/Producers%20MapExisting.pdf and http://www.biodiesel.org/pdf_files/ 

fuelfactsheets/Production_graph_slide.pdf (both 

accessed April 27, 2009). 

region).144 A significant portion of the 

2007 and 2008 production was exported 

to Europe or Asia where fuel prices and 

additional tax subsidies on top of those 

provided in the U.S. help cover 

transportation overseas and offset high 

feedstock costs. The Energy Information 

Administration is beginning to collect 

data on biodiesel imports and exports, 

but reports are not expected until later 

in 2009. Therefore precise figures are 

not available on what fraction of 

production was consumed domestically, 

but sources familiar with the industry 

suggest exports may have been as much 

as 200 million gallons in 2007 and 

likely more in 2008.145 We do not 

account for any biodiesel exports in our 

analysis, though there will be sufficient 

plant capacity to produce material 

beyond the volumes required in the 

EISA should an export market exist. 

To perform our distribution and 

emission impacts analyses for this 

proposal, it was necessary to forecast 

the state of the biodiesel industry in the 

timeframe of the fully-phased-in RFS. In 

general, this consisted of reducing the 

over-capacity to be much closer to the 

amount demanded, which we assumed 

to be equal to the requirement under the 

EISA given uncertainties about 

feedstock prices and changes in tax 

incentives in the long term. This was 

accomplished by considering as 

screening factors the current production 

and sales incentives in each state as 

well as each plant’s primary feedstock 

type and whether it was BQ–9000 

certified.146 Going forward producers 

will compete for feedstocks and markets 

will consolidate. During this period the 

number of operating plants is expected 

to shrink, with surviving plants adding 

feedstock segregation and pre-treatment 

capabilities, giving them flexibility to 

process any mix of feedstocks available 

in their area. By the end of this period 

we project a mix of large regional plants 

and some smaller plants taking 

advantage of local market niches, with 

an overall average capacity utilization 

around 80% for dedicated fuel plants. 

Table V.B.4–2 summarizes this forecast. 

See Section 1.5.4 of the DRIA for more 

details. 

TABLE V.B.4–2—SUMMARY OF PROJECTED BIODIESEL INDUSTRY CHARACTERIZATION USED IN OUR ANALYSES 147

2008 2022 

Total production capacity 

on-line (million gal/yr) .... 2,610 1,050 

Number of operating 

plants ............................. 176 35 

Median plant size (million 

gal/yr) ............................ 5 30 

Total biodiesel production 

(million gal) .................... 700 810 

Average plant utilization ... 0.27 0.77 

ii. Renewable Diesel 

Renewable diesel is a fuel (or 

blendstock) produced from animal fats, 

vegetable oils, and waste greases using 

chemical processes similar to those 

employed in petroleum hydrotreating. 

These processes remove oxygen and 

saturate olefins, converting the 

triglycerides and fatty acids into 

paraffins. Renewable diesel typically 

has higher cetane, lower nitrogen, and 

lower aromatics than petroleum diesel 

fuel, while also meeting stringent sulfur 

standards. 

In comparison to biodiesel, renewable 

diesel has improved storage, stability, 

and shipping properties as a result of 

the oxygen and olefins in the feedstock 

being removed. This allows renewable 

diesel fuel to be shipped in existing 

petroleum pipelines used for 

transporting fuels, thus avoiding one 

significant issue with distribution of 

biodiesel. For more on fuel distribution, 

refer to Section V.C. 

Considering that this industry is still 

in development and that there are no 

long-term projections of production 

volume, we base our production 

estimates primarily on the potential 

volume of feedstocks for this process, in 

the context of recent industry project 

announcements involving proven 

technology. We project that 

approximately two-thirds of renewable 

diesel will be produced at existing 

petroleum refineries, and half will be 

co-processed with petroleum (thus 

prohibiting it from counting as 

‘‘biomass-based diesel’’ under the 

EISA). Tables V.B.4–3 and V.B.4–4 

summarize these volumes. 

TABLE V.B.4–3—PROJECTED RENEWABLE DIESEL VOLUMES BY PRODUCTION CATEGORY

[Million gallons in 2022] 

Existing 

facility New facility 

Co-processed with petroleum .......................................................................................................................................... 188 — 

Not co-processed with petroleum .................................................................................................................................... 63 125 

b. Feedstock Availability 

The primary feedstock for domestic 

biodiesel production has historically 

been soybean oil, with other plant and 

animal fats as well as recycled greases 

making up a smaller but significant 

portion of the biodiesel pool. 

Agricultural commodity modeling we 

have done for this proposal (see Section 

IX.A) suggests that soybean oil 

production will stay relatively flat in the 

future, causing supplies to tighten and 

prices to rise as demand increases for 

biofuels and food uses worldwide. The 

output of these models suggests that 

domestic soy oil production could 

support about 550 million gallons per 

year in 2022. This material is most 

likely to be processed by biodiesel 

plants due to the large available 

capacity of these facilities and their 

proximity to soybean production. 

Compared to other feedstocks, virgin 

plant oils are more easily processed into 

biofuel via simple transesterification 

due to their homogeneity of 

composition and lack of contaminants. 

Another source of feedstock which 

could provide increasing and significant 

volume is oil extracted from corn or its 

co-products in the dry mill ethanol 

production process. Sometimes referred 

to as corn fractionation or dry 

separation, these processes get 

additional products of value from the 

dry milling process. This idea is not 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25001 

148See Table 3 in Mueller, Steffen. An analysis 

of the projected energy use of future dry mill corn 

ethanol plants (2010–2030). October 10, 2007. 

Available at http://www.chpcentermw.org/pdfs/ 

2007CornEthanolEnergySys.pdf. 

149Based on plant capacities reported by the 

National Biodiesel Board and data reported by F.O. 

Licht. 

150Based on statements from the National 

Renderer’s Association. 

151The location of biofuel production facilities 

and where biofuels would be used is discussed in 

Sections 1.5 and 1.7 of the DRIA respectively and 

earlier in this Section V of the preamble. 

new, as existing wet mill plants create 

several product streams from their corn 

input, including oil. Corn fractionation 

can be seen as a way to get some of this 

added value without incurring the larger 

capital costs and potentially lower 

ethanol yields associated with wet mill 

plants. More detailed discussion of 

these processes and how they affect the 

co-product stream(s) can be found in 

DRIA Section 1.4.1.3. 

The corn oil process on which we 

have chosen to focus for cost and 

volume estimates in this proposal is one 

that extracts oil from the thin stillage 

after fermentation (the non-ethanol 

liquid material that typically becomes 

part of distillers’ grains with solubles). 

We believe installation of this type of 

equipment will be attractive to industry 

because it can be added onto an existing 

dry mill plant and does not impact 

ethanol yields since it does not process 

the corn prior to fermentation. 

Depending on the configuration, such a 

system can extract 20–50% of the oil 

from the co-product streams, and 

produces a distressed corn oil (nonfood-grade, with some free fatty acids 

and/or oxidation by-products) product 

stream which can be used as feedstock 

by biodiesel facilities. Since it offers 

another stream of revenue, we believe it 

is reasonable to expect about 40% of 

projected total ethanol production to 

implement some type of oil extraction 

process by 2022, generating 

approximately 150 million gallons per 

year of corn oil biofuel feedstock.148 We 

expect this material to be processed in 

biodiesel plants. 

Rendered animal fats and reclaimed 

cooking oils and greases are another 

potentially significant source of 

biodiesel feedstock. We estimate that 

just two to four percent of biodiesel in 

2007 was produced from waste cooking 

oils and greases, though this number is 

likely higher more recently.149 Tyson 

Foods, in joint efforts with 

ConocoPhilips and Syntroleum, 

announced construction plans in 2008 

for renewable diesel production 

facilities to begin operating in 2010 and 

producing up to 175 million gallons 

annually (combined capacity). By the 

end of our projection period, as much as 

30% of rendered fats and waste grease 

could be converted to biofuel while still 

supporting production of pet food, 

soaps and detergents, and other 

oleochemicals.150 We request comment 

from members of these industries on 

any potential impacts of diversion of 

rendered materials to biofuel. 

Under this assumption, this material 

could make approximately 500 million 

gallons of biofuel (though we have not 

chosen to allocate all of it in our 

analyses here). We estimate this type of 

material could be most economically 

made into renewable diesel in the long 

term, as that process does not have the 

same sensitivities to free fatty acids and 

other contaminates typically present in 

waste greases as the biodiesel process; 

however, some amount of this material 

may continue to be processed in 

biodiesel plants that have acid 

pretreatment capabilities where it makes 

economic sense. Recent market shifts 

and changes in tax subsidies enacted 

after analyses were done for this NPRM 

have affected the relative economics of 

using waste fats and greases for 

biodiesel versus renewable diesel. We 

will reevaluate our assumptions in the 

FRM. 

Our analysis of the countries with the 

most potential to produce and consume 

biodiesel in the future suggests that 

supplies of finished biodiesel will be 

tight, and prices of its feedstocks will 

remain high. Supplies to the U.S. will 

be limited by biofuel mandates and 

targets of other countries, preferential 

shipment of biodiesel to European and 

Asian nations, and the speed at which 

non-traditional crops such as jatropha 

can be developed. Thus, we cannot at 

this time project more than negligible 

amounts of biodiesel or its feedstocks 

being available for import into the U.S. 

in the future. For more discussion of 

international movement of biodiesel and 

its feedstocks, refer to Section 1.1 of the 

DRIA. 

Table V.B.4–4 shows the projected 

potential contribution of these sources 

we have chosen to quantify. Other 

potential, but less certain, sources for 

biodiesel feedstocks include conversion 

of some existing croplands used for 

soybeans to higher-yielding oilseed 

crops. Production of oil from algae 

farms is also being investigated by a 

number of companies and universities 

as a source of biofuel feedstock. For 

additional discussion of such sources, 

refer to Section 1.1 of the DRIA. 

TABLE V.B.4–4—ESTIMATED POTENTIAL BIODIESEL AND RENEWABLE DIESEL VOLUMES IN 2022 

[Million gallons of fuel] 

Biomass-based diesel Other 

advanced 

biofuel 

Biodiesel Renewable 

diesel Renewable 

diesel 

Virgin plant oils ........................................................................................................................................ 660 — — 

Corn fractionation .................................................................................................................................... 150 — — 

Rendered fats and greases ..................................................................................................................... — 188 188 

C. Renewable Fuel Distribution 

The following discussion pertains to 

the distribution of biofuels. A 

discussion of the distribution of biofuel 

feedstocks and co-products is contained 

in Section 1.3.3 and 5.1 of the DRIA 

respectively. In conducting our analysis 

of biofuel distribution, we took into 

account the projected size and location 

of biofuel production facilities and 

where we project biofuels would be 

used.151

The current motor fuel distribution 

infrastructure has been optimized to 

facilitate the movement of petroleumbased fuels. Consequently, there are 

very efficient pipeline-terminal 

networks that move large volumes of 

petroleum-based fuels from production/ 

import centers on the Gulf Coast and the 

Northeast into the heartland of the 

25002 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

152 ‘‘Ethanol Transportation Backgrounder, 

Expansion of U.S. Corn-based Ethanol from the 

Agricultural Transportation Perspective’’, USDA, 

September 2007, http://www.ams.usda.gov/tmd/ 

TSB/EthanolTransportationBackgrounder09-17- 

07.pdf. 

153For example: (1) The Biomass Research and 

Development Board, a government study group, has 

formed a task group on biofuels distribution 

infrastructure that is composed of experts on 

biofuel distribution from a broad range of 

governmental agencies. (2) The National 

Commission on Energy Policy, an independent 

advisory group, has formed a task group of fuel 

distribution experts to make recommendations on 

the steps needed to facilitate the distribution of 

biofuels. (3) The Association of Oil Pipelines is 

conducting research to evaluate what steps are 

necessary to allow the distribution of ethanol 

blends by pipeline. 

154http://www.ers.usda.gov/FarmBill/2008/ 

Titles/TitleIXEnergy.htm#infrastructure. 

155Additional discussion can be found in Section 

1.6 of the DRIA. 

156The costs associated with making the 

necessary changes to the fuel distribution 

infrastructure are discussed in Section VIII.B of 

today’s preamble. 

157Biogasoline might also potentially be treated 

as finished fuel. 

158The projected location of biofuel plants would 

not be affected by the choice of whether they are 

designed to produce ethanol, distillate fuel, biogasoline, or butanol. Proximity to the feedstock 

would continue to be the predominate 

consideration. The use of pipelines is being 

considered for the shipment of bio-oils 

manufactured from cellulosic feedstocks to 

refineries where they could be converted into 

renewable diesel fuel or renewable gasoline. The 

distribution of biofuel feedstocks is discussed in 

Section 1.3 of the DRIA. 

159Stress corrosion cracking could lead to a 

pipeline leak. The potential impacts on water from 

today’s proposal are discussed in Section X of 

today’s preamble. 

160 Different grades of gasoline and diesel fuel are 

typically shipped in multi-product pipelines in 

batches that abut each other. To the extent possible, 

products are sequenced in a way to allow the 

interface mixture between batches to be cut into one 

of the adjoining products. In cases where diesel fuel 

abuts gasoline in the pipeline, the resulting mixture 

must typically be reprocessed into its component 

parts by distillation for resale as gasoline and diesel 

fuel. 

161 Gasoline-ethanol mixtures can be blended into 

finished gasoline. 

162Association of Oil Pipelines: http://aopl.org/ 

go/searchresults/888/?q=ethanol&sd=&ed=. 

‘‘Hazardous Liquid Pipelines Transporting Ethanol, 

Ethanol Blends, and Other Biofuels’’, Notice of 

policy statement and request for comment, Pipeline 

and Hazardous Materials Safety Administration, 

Department of Transportation, August 10, 2007, 72 

FR 45002. 

country. In contrast, the majority of 

renewable fuel is expected to be 

produced in the heartland of the 

country and will need to be shipped to 

the coasts, flowing roughly in the 

opposite direction of petroleum-based 

fuels. This limits the ability of 

renewable fuels to utilize the existing 

fuel distribution infrastructure. 

The modes of distributing renewable 

fuels to the end user vary depending on 

constraints arising from their physical/ 

chemical nature and their point of 

origination. Some fuels are compatible 

with the existing fuel distribution 

system, while others currently require 

segregation from other fuels. The 

location of renewable fuel production 

plants is also often dictated by the need 

to be close to the source of the 

feedstocks used rather than to fuel 

demand centers or to take advantage of 

the existing petroleum product 

distribution system. Hence, the 

distribution of renewable fuels raises 

unique concerns and in many instances 

requires the addition of new 

transportation, storage, blending, and 

retail equipment. 

Significant challenges must be faced 

in reconfiguring the distribution system 

to accommodate the large volumes of 

ethanol and to a lesser extent biodiesel 

that we project will be used. While 

some uncertainties remain, particularly 

with respect to the ability of the market 

to support the use of the volume of E85 

needed, no technical barriers appear to 

be insurmountable. The response of the 

transportation system to date to the 

unprecedented increase in ethanol use 

is encouraging. A U.S. Department of 

Agriculture (USDA) report concluded 

that logistical concerns have not 

hampered the growth in ethanol 

production, but that concerns may arise 

about the adequacy of transportation 

infrastructure as the growth in ethanol 

production continues.152

Considerable efforts are underway by 

individual companies in the fuel 

distribution system, consortiums of 

such companies, industry associations, 

independent study groups, and interagency governmental organizations to 

evaluate what steps may be necessary to 

facilitate the necessary upgrades to the 

distribution system to support 

compliance with the RFS2 standards.153

EPA will continue to participate/ 

monitor these efforts as appropriate to 

keep abreast of potential problems in 

the biofuel distribution system which 

might interfere with the use of the 

volumes of biofuels that we project will 

be needed to comply with the RFS2 

standards. The 2008 Farm Act (Title IX) 

requires USDA, DOE, DOT, and EPA to 

conduct a biofuels infrastructure study 

that will assess infrastructure needs, 

analyze alternative development 

approaches, and provide 

recommendations for specific 

infrastructure development actions to be 

taken.154

Considerations related to the 

distribution of ethanol, biodiesel, and 

renewable diesel are discussed in the 

following sections as well as the 

changes to each segment in the 

distribution system that would be 

needed to support the volumes of these 

biofuels that we project would be used 

to satisfy the RFS2 standards.155 We 

request comments on the challenges that 

will be faced by the fuel distribution 

system under the RFS2 standards and 

on what steps will be necessary to 

facilitate making the necessary 

accommodations in a timely fashion.156

To the extent that biofuels other than 

ethanol and biodiesel are produced in 

response to the RFS2 standards, this 

might lessen the need for added 

segregation during distribution. 

Distillate fuel produced from cellulosic 

feedstocks might be treated as 

petroleum-based diesel fuel blendstocks 

or a finished distillate fuel in the 

distribution system. Likewise, biogasoline or bio-butanol could 

potentially be treated as petroleumbased gasoline blendstocks.157 This also 

might open the possibility for additional 

transport by pipeline. However, the 

location of plants that produce such 

biofuels relative to petroleum pipeline 

origination points would continue to be 

an issue limiting the usefulness of 

existing pipelines for biofuel 

distribution.158

1. Overview of Ethanol Distribution 

Pipelines are the preferred method of 

shipping large volumes of petroleum 

products over long distances because of 

the relative low cost and reliability. 

Ethanol is currently not commonly 

shipped by pipeline because it can 

cause stress corrosion cracking in 

pipeline walls and its affinity for water 

and solvency can result in product 

contamination concerns.159 Shipping 

ethanol in pipelines that carry distillate 

fuels as well as gasoline also presents 

unique difficulties in coping with the 

volumes of a distillate-ethanol mixture 

which would typically result.160 It is not 

possible to re-process this mixture in 

the way that diesel-gasoline mixtures 

resulting from pipeline shipment are 

currently handled.161 Substantial testing 

and analysis is currently underway to 

resolve these concerns so that ethanol 

may be shipped by pipeline either in a 

batch mode or blended with petroleumbased fuel.162 By the time of the 

publication of this proposal, results of 

these evaluations may be available 

regarding what actions are necessary by 

multi-product pipelines to overcome 

safety and product contamination 

concerns associated with shipping 10% 

ethanol blends. A short gasoline 

pipeline in Florida has begun shipping 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25003 

163Article on shipment of ethanol in Kinder 

Morgan pipeline: http://www.ethanolproducer.com/ 

article.jsp?article_id=5149. 

164Some small petroleum product refineries are 

currently limited in their ability to ship products 

by pipeline because their relatively low volumes 

were not sufficient to justify connection to the 

pipeline distribution system. 

165A discussion of the projected location of 

cellulosic ethanol plants is contained in Section 1.5 

of the DRIA. 

166Magellan and Poet joint assessment of 

dedicated ethanol pipeline: http:// 

www.magellanlp.com/news/2009/20090316_5.htm. 

167 ‘‘Ethanol Transportation Backgrounder, 

Expansion of U.S. Corn-based Ethanol from the 

Agricultural Transportation Perspective’’, USDA, 

September 2007, http://www.ams.usda.gov/tmd/ 

TSB/EthanolTransportationBackgrounder09-17- 

07.pdf. 

168Hub ethanol receipt terminals can be located 

at large petroleum terminals or at rail terminals. 

169The cost of retail dispensing hardware which 

is tolerant to ethanol blends greater than E10 is 

discussed in Section VIII.B. of today’s preamble and 

discussed in more detail in Section 4.2 of the DRIA. 

170See Section V.D of today’s preamble for a 

discussion of issues related to use of the projected 

volumes of ethanol that would be produced to 

comply with the RFS2 standards. 

171Underwriters Laboratory certifies retail 

refueling equipment. UL stated that they have data 

which indicates that the use of fuel dispensers 

certified for up to E10 blends to dispense blends up 

to a maximum ethanol content of 15 volume 

percent would not result in critical safety concerns 

(http://www.ul.com/newsroom/newsrel/ 

nr021909.html). Based on this, UL stated that it 

would support authorities having jurisdiction who 

decide to permit legacy equipment originally 

certified for up to E10 blends to be used to dispense 

up to 15 volume percent ethanol. The UL 

announcement did address the compatibility of 

underground storage tank systems with greater than 

E10 blends. 

batches of ethanol.163 Thus, existing 

petroleum pipelines in some areas of the 

country might play a role in the 

shipment of ethanol from the points of 

production/importation to petroleum 

terminals. 

However, the location of ethanol 

plants in relation to existing pipeline 

origination points will limit the role of 

existing pipelines in the shipment of 

ethanol.164 Current corn ethanol 

production facilities are primarily 

located in the Midwest far from the 

origination points of most existing 

product pipelines and the primary 

gasoline demand centers. We project 

that a substantial fraction of future 

cellulosic ethanol plants will also be 

located in the Midwest, although a 

greater proportion of cellulosic plants 

are expected to be dispersed throughout 

the country compared to corn ethanol 

plants. The projected locations for this 

subset of future cellulosic ethanol plants 

more closely coincide with the 

origination points of product pipelines 

in the Gulf Coast.165 Imported ethanol 

could also be brought into ports near the 

origination point of product pipelines in 

the Gulf Coast and the Northeast. 

Nevertheless, the majority of ethanol 

will continue to be produced at 

locations distant from the origination 

points of product pipelines and gasoline 

demand centers. The gathering of 

ethanol from production facilities 

located in the Midwest and shipment by 

barge down the Mississippi for 

introduction to pipelines in the Gulf 

Coast is under consideration. However, 

the additional handling steps to bring 

the ethanol to the pipeline origin points 

in this manner could negate any 

potential benefit of shipment by existing 

petroleum pipelines compared to direct 

shipment by rail. 

Evaluations are also currently 

underway regarding the feasibility of 

constructing a new dedicated ethanol 

pipeline from the Midwest to the East 

Coast.166 Under such an approach, 

ethanol would be gathered from a 

number of Midwest production facilities 

to provide sufficient volume to justify 

pipeline operation. To the extent that 

ethanol production would be further 

concentrated in the Midwest due to the 

siting of cellulosic ethanol plants, this 

would tend to help justify the cost of 

installing a dedicated ethanol pipeline. 

Substantial issues would need to be 

addressed before construction on such a 

pipeline could proceed, including those 

associated with securing new rights-ofways and establishing sufficient surety 

regarding the return on the several 

billion dollar investment. 

Due to the uncertainties regarding the 

degree to which pipelines will be able 

to participate in the transportation of 

ethanol, we assumed that ethanol will 

continue to be transported by rail, barge, 

and truck to the terminal where it will 

be blended into gasoline. The 

distribution by these modes can be 

further optimized primarily through the 

increased shipment by unit train and 

installation of additional hub delivery 

terminals that can accept large volumes 

of ethanol for further distribution to 

satellite terminals. To the extent that 

pipelines do eventually play a role in 

the distribution of ethanol, this could 

tend to reduce distribution costs and 

improve reliability in supply. 

USDA estimated that in 2005 

approximately 60% of ethanol was 

transported by rail, 30% was 

transported by tank truck, and 10% was 

transported by barge.167 Denatured 

ethanol is shipped from production/ 

import facilities to petroleum terminals 

where it is blended with gasoline. When 

practicable, shipment by unit train is 

the preferred method of rail shipment 

rather than shipping on a manifest rail 

car basis. The use of unit trains, 

sometimes referred to as a virtual 

pipeline, substantially reduces shipping 

costs and improves reliability. Unit 

trains are composed entirely of 70–100 

ethanol tank cars, and are dedicated to 

shuttle back and forth to large hub 

terminals.168 Manifest rail car shipment 

refers to the shipment of ethanol in rail 

tank cars that are incorporated into 

trains which are composed of a variety 

of other commodities. Unit trains can be 

assembled at a single ethanol 

production plant or if a group of plants 

is not large enough to support such 

service individually, can be formed at a 

central facility which gathers ethanol 

from a number of producers. The Manly 

Terminal in Iowa, which is the first 

such ethanol gathering facility, accepts 

ethanol from a number of nearby 

ethanol production facilities for 

shipment by unit train. Regional (Class 

2) railroad companies are an important 

link bringing ethanol to gathering 

facilities for assembly into unit trains 

for long-distance shipment by larger 

(Class 1) railroads. Ethanol is sometimes 

carried by multiple modes before finally 

arriving at the terminal where it is 

blended into gasoline. For example, 

some ethanol is currently shipped from 

the Midwest to a hub terminal on the 

East Coast by unit train where a portion 

is further shipped to satellite terminals 

by barge or tank truck. 

Ethanol is blended into gasoline at 

either 10 or 85 volume percent at 

terminals (to produce E10 and E85) for 

delivery to retail and fleet facilities by 

tank truck. Special retail delivery 

hardware is needed for E85 which can 

be used in flexible fuel vehicles only.169

The large volume of ethanol that we 

project will be used by 2022 means that 

more ethanol will need to be used than 

can be accommodated by blending to 

the current legal limit of 10% in all of 

the gasoline used in the country. This 

will require the installation of a 

substantial number of new E85 refueling 

facilities and the addition of a 

substantial number of flex-fuel vehicles 

to the fleet. Concerns have been raised 

regarding the inducements that would 

be necessary for retailers to install the 

needed E85 facilities and for consumers 

to purchase E85.170 As discussed in 

Section V.D. of today’s preamble, this is 

prompting many to evaluate whether a 

mid-level ethanol blend (e.g. E15) might 

be allowed for use in existing (non-flexfuel) vehicles. Current refueling 

equipment (not designed for E85) is 

only certified for ethanol blends up to 

10 volume percent (E10).171 Hence, if a 

mid-level ethanol blend were to be 

introduced, fuel retail facilities would 

need to ensure that the equipment used 

to store/dispense mid-level ethanol 

25004 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

172Although it has yet to be established, most 

underground steel storage tanks themselves would 

likely be compatible with ethanol blends greater 

than 10 percent. The compatibility of piping, 

submersed pumps, gaskets, and seals associated 

with these tanks with ethanol blends greater than 

10% would also need to be evaluated. Some 

fiberglass tanks are incompatible and would need 

to be replaced. It is difficult and sometimes 

impossible to verify the suitability of underground 

storage tanks and tank-related equipment for E85 

use. The State of California prohibits the conversion 

of underground storage tanks to E85 use. Significant 

changes to dispensers, including hoses, nozzles, 

and other miscellaneous fittings would be needed 

to ensure they are compatible with ethanol blends 

greater than 10 percent. 

173 Joint UL/DOE Legacy System Certification 

Clarification http://www.ul.com/global/eng/ 

documents/offerings/industries/chemicals/ 

flammableandcombustiblefluids/development/ 

UL_DOE_LegacySystemCertification.pdf. 

174Biodiesel feedstocks are typically 

preprocessed to oil prior to shipment to biodiesel 

production facilities. This can substantially reduce 

the volume of feedstocks shipped to biodiesel 

plants relative to ethanol plants. 

175Section 1.2 contains a discussion of our 

projections regarding the location of biodiesel 

production facilities. 

176 Industry evaluations are currently underway 

to resolve these concerns. 

177Either co-processed with crude oil or 

processed in separate units at the refinery for 

blending with other refinery diesel blendstocks. 

blends is compatible with the mid-level 

ethanol blend.172 Underwriters 

Laboratories has one certification 

standard for fuel retail equipment that 

covers ethanol blends up to 10%, and a 

separate certification standard for 

equipment that dispenses ethanol 

blends above 10% (including E85).173

Should other biofuels be introduced 

that do not require differentiation from 

diesel fuel or gasoline in place of some 

of the volume of ethanol that we project 

would be used under the RFS2 

standards, this may tend to reduce the 

need for changes at fuel retail facilities 

and the need for flex-fuel vehicles. 

Concerns about the difficulties/costs 

associated with expanding the ethanol 

distribution infrastructure and adding a 

sufficient number of vehicles capable of 

using 10% ethanol to fleet is generating 

increased industry interest in renewable 

diesel and gasoline which would be 

more transparent to the existing fuel 

distribution system. 

2. Overview of Biodiesel Distribution 

Biodiesel is currently transported 

from production plants by truck, 

manifest rail car, and by barge to 

petroleum terminals where it is blended 

with petroleum-based diesel fuel. 

Unblended biodiesel must be 

transported and stored in insulated/ 

heated containers in colder climes to 

prevent gelling. Insulated/heated 

containers are not needed for biodiesel 

that has been blended with petroleumbased diesel fuel (i.e., B2, B5). Biodiesel 

plants are not as dependent on being 

located close to feedstock sources as are 

corn and cellulosic ethanol plants.174

Biodiesel feedstocks are typically 

preprocessed to oil prior to shipment to 

biodiesel production facilities. This can 

substantially reduce the volume of 

feedstocks shipped to biodiesel plants 

relative to ethanol plants, and has 

allowed some biodiesel plants to be 

located adjacent to petroleum terminals. 

Biodiesel production facilities are more 

geographically dispersed than ethanol 

facilities and the production volumes 

also tend to be smaller than ethanol 

facilities.175 These characteristics in 

combination with the smaller volumes 

of biodiesel that we project will be used 

under the RFS2 standards compared to 

ethanol allow relatively more biodiesel 

to be used within trucking distance of 

the production facility. However, we 

project that there will continue to be a 

strong and growing demand for 

biodiesel as a blending component in 

heating oil which could not be satisfied 

alone by local sources of production. It 

is likely that state biodiesel mandates 

will also need to be satisfied in part by 

out-of-state production. Fleets are also 

likely to continue to be a substantial 

biodiesel user, and these will not always 

be located close to biodiesel producers. 

Thus, we are assuming that a substantial 

fraction of biodiesel will continue to be 

shipped long distances to market. 

Downstream of the petroleum terminal, 

B2 and B5 can be distributed in the 

same manner as petroleum diesel. 

Concerns remain regarding the 

shipment of biodiesel by pipeline 

(either by batch mode or in blends with 

diesel fuel) related to the contamination 

of other products (particularly jet fuel), 

the solvency of biodiesel, and 

compatibility with pipeline gaskets and 

seals.176 The smaller anticipated 

volumes of biodiesel and the more 

dispersed and smaller production 

facilities relative to ethanol also make 

biodiesel a less attractive candidate for 

shipment by pipeline. Due to the 

uncertainties regarding the suitability of 

transporting biodiesel by pipeline, we 

assumed that biodiesel which needs to 

be transported over long distance will 

be carried by manifest rail car and to a 

lesser extent barge. Due to the relatively 

small plant size and dispersion of 

biodiesel plants, we anticipate the 

volumes of biodiesel that can be 

gathered at a single location will 

continue to be insufficient to justify 

shipment by unit train. To the extent 

that pipelines do eventually play a role 

in the distribution of biodiesel, this 

could tend to reduce distribution costs 

and improve reliability in supply. 

3. Overview of Renewable Diesel 

Distribution 

We believe that renewable diesel fuel 

will be confirmed to be sufficiently 

similar to petroleum-based diesel fuel 

blendstocks with respect to distribution 

system compatibility. Hence, renewable 

diesel fuel could be treated in the same 

manner as any petroleum-based diesel 

fuel blendstock with respect to transport 

in the existing petroleum distribution 

system. Approximately two-thirds of 

renewable diesel fuel is projected to be 

produced at petroleum refineries.177

The transport of such renewable diesel 

fuel would not differ from petroleumbased diesel fuel since it would be 

blended to produce a finished diesel 

fuel before leaving the refinery. The 

other one-third of renewable diesel fuel 

is projected to be produced at standalone facilities located more closely to 

sources of feedstocks. We anticipate that 

such renewable diesel fuel would be 

shipped by tank truck to nearby 

petroleum terminals where it would be 

blended directly into diesel fuel storage 

tanks. Because of its high cetane and 

value, we anticipate that all renewable 

diesel fuel would likely be blended with 

petroleum based diesel fuel prior to use. 

Downstream of the terminal, renewable/ 

petroleum diesel fuel mixtures would be 

distributed the same as petroleum 

diesel. 

4. Changes in Freight Tonnage 

Movements 

To evaluate the magnitude of the 

challenge to the distribution system up 

to the point of receipt at the terminal, 

we compared the growth in freight 

tonnage for all commodities from the 

AEO 2007 reference case to the growth 

in freight tonnage under the RFS2 

standards in which ethanol increases, as 

does the feedstock (corn) and coproducts (distillers grains). We did not 

include a consideration of the 

distribution of cellulosic ethanol 

feedstocks on freight tonnage for the 

proposal. We intend to evaluate this in 

the final rule. For purposes of this 

analysis, we focused on only the ethanol 

portion of the renewable fuel goals for 

ease of calculation and because ethanol 

represents the vast majority of the total 

volume of biofuel. The resulting 

calculations serve as an indicator of 

changes in freight tonnages associated 

with increases in renewable fuels. We 

calculated the freight tonnage for the 

total of all modes of transport as well as 

the individual cases of rail, truck, and 

barge. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25005 

178http://www.ops.fhwa.dot.gov/freight/ 

freight_analysis/faf/index.htm. 179 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National 

Laboratory, March 2009. 

180 Industry groups include the Alliance of 

Automobile Manufacturers, American Chemistry 

Council, and the National Industrial Transportation 

League; governmental agencies include the Federal 

Railroad Administration (FRA), the Government 

Accountability Office (GAO), and the American 

Association of State Highway Transportation 

Officials (AASHTO). Testimony for the STB public 

hearings includes Ex Parte No. 671, Rail Capacity 

and Infrastructure Requirements and Ex Parte No. 

672, Rail Transportation and Resources Critical to 

the Nation’s Energy Supply. 

181 ‘‘The Importance of Adequate Rail 

Investment’’, Association of American Railroads, 

http://www.aar.org/GetFile.asp?File_ID=150. 

182AASHTO Freight-Rail Bottom-Line Report, 

2003. 

183The railroads interviewed by GAO were 

generally unwilling to discuss their future 

investment plans with the GAO. Therefore, GAO 

was unable to comment on how Class I freight rail 

companies are likely to choose among their 

competing investment priorities for the future, 

including those of the rail infrastructure, GAO 

Continued 

In calculating the reference case 

percent growth rate in total freight 

tonnage, we used data compiled by the 

Federal Highway Administration to 

calculate the tonnages associated with 

these commodities.178 We then 

calculated the growth in freight tonnage 

for 2022 under the RFS2 standards and 

compared the difference with the 

reference case. The comparisons 

indicate that across all transport modes, 

the incremental increase in freight 

tonnage of ethanol and accompanying 

feedstocks and co-products associated 

with the increased ethanol volume 

under the RFS2 standards are small. The 

percent increase for total freight across 

all modes (including pipeline) by 2022 

is 0.9 percent. Because pipelines 

currently do not carry ethanol, and the 

increase in the volume of ethanol used 

in motor vehicles displaces a 

corresponding volume of gasoline, 

pipelines showed a decrease in the total 

tonnage carried due to a decrease in the 

volume of gasoline carried by pipeline. 

The displaced gasoline also resulted in 

some decrease in tonnage in other 

modes that slightly reduced the overall 

increases in tonnage reflected in the 

totals. 

To further evaluate the magnitude of 

the increase in freight tonnage under the 

RFS2 standards, we calculated the 

portion of the total freight tonnage for 

rail, barge, and truck modes made up of 

ethanol-related freight for both the 2022 

and control cases. The freight associated 

with ethanol constitutes only a very 

small portion of the total freight tonnage 

for all commodities. Specifically, 

ethanol freight represents approximately 

0.5% and 2.5% of total freight for the 

reference case and RFS2 standards case, 

respectively. The results of this analysis 

suggest that it should be feasible for the 

distribution infrastructure upstream of 

the terminal to accommodate the 

additional freight associated with this 

RFS2 standards especially given the 

lead time available. Specific issues 

related to transportation by rail, barge, 

and tank truck are discussed in the 

following sections. We intend to 

incorporate the results of a recently 

completed study by Oak Ridge National 

Laboratory (ORNL) on the potential 

constraints in ethanol distribution into 

the analysis for the final rule.179 The 

ORNL study concluded that the increase 

in ethanol transport would have 

minimal impacts on the overall 

transportation system. However, the 

ORNL study did identify localized areas 

where significant upgrades to the rail 

distribution system would likely be 

needed. 

5. Necessary Rail System 

Accommodations 

Many improvements to the freight rail 

system will be required in the next 15 

years to keep pace with the large 

increase in the overall freight demand. 

Improvements to the freight railroad 

infrastructure will be driven largely by 

competition in the burgeoning intermodel transport sector. As inter-model 

freight represents the vast majority of all 

freight hauled by these railroads, the 

biofuels transport sector can be 

expected to benefit from the 

infrastructure build-out resulting from 

inter-model transport sector 

competition. As such, most of the 

needed upgrades to the rail freight 

system are not specific to the transport 

of renewable fuels and would be needed 

irrespective of today’s proposed rule. 

We also expect that the excess rail 

capacity associated with inter-model 

build-out to be adequately large to 

absorb potential increases in truck 

transport associated with fuel cost 

increases. The modifications required to 

satisfy the increase in demand include 

upgrading tracks to allow the use of 

heavier trains at faster speeds, the 

modernization of train braking systems 

to allow for increased traffic on rail 

lines, the installation of rail sidings to 

facilitate train staging and passage 

through bottlenecks. 

Some industry groups 180 and 

governmental agencies in discussions 

with EPA, and in testimony provided 

for the Surface Transportation Board 

(STB) expressed concerns about the 

ability of the rail system to keep pace 

with the large increase in demand even 

under the reference case (27% by 2022). 

For example, the electric power 

industry has had difficulty keeping 

sufficient stores of coal in inventory at 

power plants due to rail transport 

difficulties and has expressed concerns 

that this situation will be exacerbated if 

rail congestion worsens. One of the 

more sensitive bottleneck areas with 

respect to the movement of ethanol from 

the Midwest to the East coast is Chicago. 

The City of Chicago commissioned its 

own analysis of rail capacity and 

congestion, which found that the lack of 

rail capacity is ‘‘no longer limited to a 

few choke points, hubs, and heavily 

utilized corridors.’’ Instead, the report 

finds, the lack of rail capacity is 

‘‘nationwide, affecting almost all the 

nation’s critically important trade 

gateways, rail hubs, and intercity freight 

corridors.’’ 

Significant private and public 

resources are focused on making the 

modifications to the rail system to cope 

with the increase in demand. Rail 

carriers report that they typically invest 

$16 to $18 billion a year in 

infrastructure improvements.181

Substantial government loans are also 

available to small rail companies to help 

make needed improvements by way of 

the Railroad Rehabilitation and 

Improvement Finance (RRIF) Program, 

administered by Federal Railroad 

Administration (FRA), as well as 

Section 45G Railroad Track 

Maintenance Credits, offered by the 

Internal Revenue Service (IRS). The 

American Association of State Highway 

Transportation Officials (AASHTO) 

estimates that between $175 billion and 

$195 billion must be invested over a 20- 

year period to upgrade the rail system 

to handle the anticipated growth in 

freight demand, according to the 

report’s base-case scenario.182 The 

report suggests that railroads should be 

able to provide up to $142 billion from 

revenue and borrowing, but that the 

remainder would have to come from 

other sources including, but not limited, 

to loans, tax credits, sale of assets, and 

other forms of public-sector 

participation. Given the reported 

historical investment in rail 

infrastructure, it may be reasonable to 

assume that rail carriers would be able 

to manage the $7.1 billion in annual 

investment from rail carriers that 

AASHTO projects would be needed to 

keep pace with the projected increase in 

freight demand. 

However, the Government Accounting 

Office (GAO) found that it is not 

possible to independently confirm 

statements made by Class I rail carriers 

regarding future investment plans.183 In 

25006 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

testimony Before the Subcommittee on Surface 

Transportation and Merchant Marine, Senate 

Committee on Commerce, Science, and 

Transportation, U.S. Senate, Freight Railroads 

Preliminary Observations on Rates, Competition, 

and Capacity Issues, Statement of JayEtta Z. Hecker, 

Director, Physical Infrastructure Issues, GAO, GAO– 

06–898T (Washington, DC: June, 21, 2006). 

184 GAO, Freight Railroads: Industry Health Has 

Improved, but Concerns about Competition and 

Capacity Should Be Addressed, GAO–07–94 

(Washington, DC: Oct. 6, 2006); GAO, Freight 

Railroads: Updated Information on Rates and Other 

Industry Trends, GAO–07–291R Freight Railroads 

(Washington, DC: Aug. 15, 2007). STB’s final report, 

entitled Report to the U.S. STB on Competition and 

Related Issues in the U.S. Freight Railroad Industry, 

is expected to be completed November, 1, 2008. 

185A discussion of how we arrived at the 

estimated number of tank cars needed is contained 

in Section 4.2 of the DRIA. 

186 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National 

Laboratory, March 2009. 

187 ‘‘The U.S. Truck Driver Shortage: Analysis and 

Forecasts’’, Prepared by Global Insights for the 

American Trucking Association, May 2005. http:// 

www.truckline.com/NR/rdonlyres/E2E789CF–F308– 

463F–8831–0F7E283A0218/0/ 

ATADriverShortageStudy05.pdf. 

addition, questions persist regarding 

allocation of these investments, with the 

Alliance of Automobile Manufacturers, 

American Chemistry Council, National 

Industrial Transportation League, and 

others expressing concern that their 

infrastructural needs may be neglected 

by the Class I railroads in favor of more 

lucrative intermodal traffic. Moreover, 

the GAO has raised questions regarding 

the competitive nature and extent of 

Class I freight rail transport. This raises 

some concern that providing sufficient 

resources to facilitate the transport of 

increasing volumes of ethanol and 

biodiesel might not be a first priority for 

rail carriers. In response to GAO 

concerns, the Surface Transportation 

Board (STB) agreed to undertake a 

rigorous analysis of competition in the 

freight railroad industry.184

Given the broad importance to the 

U.S. economy of meeting the anticipated 

increase in freight rail demand, and the 

substantial resources that seem likely to 

be focused on this cause, we believe that 

overall freight rail capacity would not 

be a limiting factor to the successful 

implementation of the biofuel 

requirements to meet the RFS2 

standards. Evidence from the recent 

ramp up of ethanol use has also shown 

that rail carriers are enthusiastically 

pursuing the shipment of ethanol. Class 

2 railroads have been particularly active 

in gathering sufficient numbers of 

ethanol cars to allow Class 1 railroads 

to ship ethanol by unit train. Likewise, 

we believe that that Class 2 railroads 

and, to a lesser extent, the trucking 

industry, will play a key role in the 

transportation of DDGs and other 

byproducts from regions with 

concentrated ethanol production 

facilities to those with significant 

livestock operations. Based on this 

recent experience, we believe that 

ethanol will be able to compete 

successfully with other commodities in 

securing its share of freight rail service. 

While many changes to the overall 

freight rail system are expected to occur 

irrespective of today’s proposed rule, a 

number of ethanol-specific 

modifications will be needed. For 

instance, a number of additional rail 

terminals are likely to be configured for 

receipt of unit trains of ethanol for 

further distribution by tank truck or 

other means to petroleum terminals. 

The placement of ethanol unit train 

receipt facilities at rail terminals would 

be particularly useful in situations 

where petroleum terminals might find it 

difficult or impossible to install their 

own ethanol rail receipt capability. We 

anticipate that ethanol storage will 

typically be installed at rail terminal 

ethanol receipt hubs over the long run. 

We do not anticipate that the rail 

industry will experience substantial 

difficulty in installing such ethanolspecific facilities once a clear long term 

demand for ethanol in the target markets 

has been established to justify the 

investment. However, the need for longterm demand to be established prior to 

the construction of such facilities will 

likely mean that the needed facilities 

will, at best, come on-line on a just-intime basis. This may lead to use of less 

efficient means of ethanol transport in 

the short term. The ability to rely on 

transloading while ethanol storage 

facilities at rail terminal ethanol receipt 

hub facilities are constructed will speed 

the optimization of the distribution of 

ethanol by rail by allowing the 

construction of ethanol storage at rail 

terminal hubs to be delayed. 

We estimate that a total of 44,000 rail 

cars would be needed to distribute the 

volumes of ethanol and biodiesel that 

we project would be used in 2022 to 

satisfy the RFS2 requirements.185 Our 

analysis of ethanol and biodiesel rail car 

production capacity indicates that 

access to these cars should not represent 

a serious impediment to meeting the 

requirements under the RFS2 standards. 

Ethanol tank car production has 

increased approximately 30% per year 

since 2003, with over 21,000 tank cars 

expected to be produced in 2007. The 

volume of these newly-produced tank 

cars, coupled with that of an existing 

tank car fleet already dedicated to 

ethanol and biodiesel transport, suggests 

that an adequate number of these tank 

cars will be in place to transport the 

proposed renewable fuel volume 

requirements in the time available. 

We request comment on the extent to 

which the rail system will be able to 

deliver the additional volumes of 

ethanol and biodiesel that we anticipate 

would be used in response to the RFS2 

standards in a timely and reliable 

fashion. A recently completed report by 

ORNL identifies specific segments of the 

rail system which would likely see the 

most significant increase in traffic due 

to increased shipments of ethanol under 

the EISA.186

6. Necessary Marine System 

Accommodations 

The American Waterway’s 

Association has expressed concerns 

about the need to upgrade the inland 

waterway system in order to keep pace 

with the anticipated increase in overall 

freight demand. The majority of these 

concerns have been focused on the need 

to upgrade the river lock system on the 

Mississippi River to accommodate 

longer barge tows and on dredging 

inland waterways to allow for 

movement of fully loaded vessels. We 

do not anticipate that a substantial 

fraction of renewable/alternative fuels 

will be transported via these arteries. 

Thus, we do not believe that the ability 

to ship ethanol/biodiesel by inland 

marine will represent a serious barrier 

to the implementation of 

implementation of the requirements 

under RFS2 standards. Substantial 

quantities of the corn ethanol coproduct dried distiller grains (DDG) is 

expected to be exported from the 

Midwest via the Mississippi River as the 

U.S. demand for DDG becomes 

saturated. We anticipate that the volume 

of exported DDG would take the place 

of corn that would be shifted from 

export to domestic use in the 

production of ethanol. Thus, we do not 

expect the increase in DDG exports to 

result in a substantial increase in river 

freight traffic. We request comment on 

the extent to which marine transport 

may be used in the transport of 

cellulosic ethanol feedstocks. 

7. Necessary Accommodations to the 

Road Transportation System 

Concerns have been raised regarding 

the ability of the trucking industry to 

attract a sufficient number of drivers to 

handle the anticipated increase in truck 

freight.187 The American Trucking 

Association projected the need for 

additional 54,000 drivers each year. We 

estimate that the growth in the use of 

biofuels through 2022 due to the RFS2 

standards would result in the need for 

a total of approximately 3,000 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25007 

188The Independent Fuel Terminal Operators 

Association represents terminals in the Northeast. 

189 It currently may take 4 to 8 months to begin 

construction of a storage tank after a contract is 

signed due to tightness in construction assets and 

steel supply. 

190 ‘‘Specification for Fuel Ethanol (Ed75–Ed85) 

for Spark-Ignition Engines’’, American Society for 

Testing and Materials standard ASTM D5798. 

191Coordinating Research Council (CRC) report 

No. E–79–2, Summary of the Study of E85 Fuel in 

the USA Winter 2006–2007, May 2007. http:// 

www.crcao.org/reports/recentstudies2007/E–79–2/ 

E–79– 

2%20E85%20Summary%20Report%202007.pdf. 

192CRC Cold Start and Warm-up E85 Driveability 

Program, http://www.crcao.com/about/ 

Annual%20Report/2007%20Annual%20Report/ 

Perform/CM–133.htm. 

193This is different from the approach taken in 

the refinery modeling which assumed that special 

blendstocks would be used to blend E85. A 

discussion of the refinery modeling can be found 

in Section 4 of the DRIA. 

194Certain accommodations for butane blenders 

into gasoline were provided in a direct final rule 

Continued 

additional trucks drivers. Given the 

relatively small number of new truck 

drivers needed to transport the volumes 

of biofuels needed to comply with the 

RFS2 standards through 2022 compared 

to the total expected increase in demand 

for drivers over the same time period 

(>750,000), we do not expect that the 

implementation of the RFS2 standards 

would substantially impact the potential 

for a shortage of truck drivers. However, 

specially certified drivers are required 

to transport ethanol and biodiesel 

because these fuels are classified as 

hazardous liquids. Thus, there may be a 

heightened level of concern about the 

ability to secure a sufficient number of 

such specially certified tank truck 

drivers to transport ethanol and 

biodiesel. The trucking industry is 

involved in efforts to streamline the 

certification of drivers for hazardous 

liquids transport and more generally to 

attract and retrain a sufficient number of 

new truck drivers. 

Truck transport of biofuel feedstocks 

to production plants and finished 

biofuels and co-products from these 

plants is naturally concentrated on 

routes to and from these production 

plants. This may raise concerns about 

the potential impact on road congestion 

and road maintenance in areas in the 

proximity of these facilities. We do not 

expect that such potential concerns 

would represent a barrier to the 

implementation of the RFS2 standards. 

The potential impact on local road 

infrastructure and the ability of the road 

network to be upgraded to handle the 

increased traffic load is an inherent part 

in the placement of new biofuel 

production facilities. Consequently, we 

expect that any issues or concerns 

would be dealt with at the local level. 

We request comment on the extent to 

which satisfying the requirements under 

the RFS2 standards might exacerbate the 

anticipated shortage of truck drivers or 

lead to localized road congestion and 

condition problems. Comment is further 

requested on the means to mitigate such 

potential difficulties to the extent they 

might exist. 

8. Necessary Terminal Accommodations 

Terminals will need to install 

additional storage capacity to 

accommodate the volume of ethanol/ 

biodiesel that we anticipate will be used 

in response to the RFS2 standards. 

Questions have been raised about the 

ability of some terminals to install the 

needed storage capacity due to space 

constraints and difficulties in securing 

permits.188 Overall demand for fuel 

used in spark ignition motor vehicles is 

expected to remain relatively constant 

through 2022. Thus, much of the 

demand for new ethanol and biodiesel 

storage could be accommodated by 

modifying storage tanks previously used 

for the gasoline and petroleum-based 

diesel fuels that would displaced by 

ethanol and biodiesel. The areas served 

by existing terminals also often overlap. 

In such cases, one terminal might be 

space constrained while another serving 

the same area may be able to install the 

additional capacity to meet the increase 

in demand. Terminals with limited 

ethanol storage (or no access to rail/ 

barge ethanol shipments) could receive 

truck shipments of ethanol from 

terminals with more substantial ethanol 

storage (and rail/barge receipt) capacity. 

The trend towards locating ethanol 

receipt and storage capability at rail 

terminals located near petroleum 

terminals is likely to be an important 

factor in reducing the need for large 

volume ethanol receipt and storage 

facilities at petroleum terminals. In 

cases where it is impossible for existing 

terminals to expand their storage 

capacity due to a lack of adjacent 

available land or difficulties in securing 

the necessary permits, new satellite 

storage or new separate terminal 

facilities may be needed for additional 

ethanol and biodiesel storage. However, 

we believe that there would be few such 

situations. 

Another question is whether the 

storage tank construction industry 

would be able to keep pace with the 

increased demand for new tanks that 

would result from today’s proposal. The 

storage tank construction industry 

recently experienced a sharp increase in 

demand after years of relatively slack 

demand for new tankage. Much of this 

increase in demand was due to the 

unprecedented increase in the use of 

ethanol. Storage tank construction 

companies have been increasing their 

capabilities which had been pared back 

during lean times.189 Given the 

projected gradual increase in the need 

for biofuel storage tanks, it seems 

reasonable to conclude that the storage 

tank construction industry would be 

able to keep pace with the projected 

demand. 

The RFG and anti-dumping 

regulations currently require certified 

gasoline to be blended with denatured 

ethanol to produce E85. The gasoline 

must meet all applicable RFG and antidumping standards for the time and 

place where it is sold. We understand 

that some parties may be blending 

butanes and or pentanes into gasoline 

before it is blended with denatured 

ethanol in order to meet ASTM 

minimum volatility specifications for 

E85 that were set to ensure proper 

drivability, particularly in the winter.190

If terminal operators add blendstocks to 

finished gasoline for use in 

manufacturing E85, the terminal 

operator would need to register as a 

refiner with EPA and meet all 

applicable standards for refiners. 

Recent testing has shown that much 

of in-use E85 does not meet minimum 

ASTM volatility specifications.191

However, it is unclear if noncompliance 

with these specifications has resulted in 

a commensurate adverse impact on 

drivability. This has prompted a reevaluation of the fuel volatility 

requirements for in-use E85 vehicles 

and whether the ASTM E85 volatility 

specifications might be relaxed.192 For 

the purpose of our analysis, we are 

assuming that certified gasoline 

currently on hand at terminals can be 

used to make up the non-ethanol 

portion of E85.193

We request comment on the extent 

that this will be the case in light of the 

projected outcome of the ASTM process. 

Comment is requested on the fraction of 

terminals that currently have butane/ 

pentane blending capability and the 

logistical/cost implications of adding 

such capability including sourcing and 

transportation issues associated with 

supplying these blending components to 

the terminal for the purpose of blending 

E85 to ASTM specifications. We also 

seek comment on whether we should 

include a separate section in the RFS2 

regulations to specify the requirements 

for producing E85, and whether we 

should provide E85 manufacturers who 

use blendstocks to produce E85 with 

any flexibilities in complying with the 

refiner requirements.194

25008 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

published on December 15, 2005 entitled, 

‘‘Modifications to Standards and Requirements for 

Reformulated and Conventional Gasoline Including 

Butane Blenders and Attest Engagements’’, 70 FR 

74552. 

195 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National 

Laboratory, March 2009. 

196See Section 1.6 of the DRIA for a discussion 

of the projected number of E85 refueling facilities 

that would be needed. There would need to be a 

total of 28,750 E85 retail facilities, 4,500 of which 

are projected to have been placed in service absent 

the RFS2 standards. 197See http://ulstandardsinfonet.ul.com/ 

outscope/0087A.html. 198All dispenser equipment except the hose used 

to dispense fuel to the vehicle has been evaluated 

by UL. Once suitable hoses have been evaluated, a 

complete E85 dispenser system can be certified by 

UL. 199See Section 4.2 of the DRIA for a discussion 

of E85 facility costs. These costs include the 

installation of 2 pumps with 4 E85 refueling 

positions at 40% of new facilities, and 1 pump with 

2 refueling positions at 60% of new facilities. A 

sensitivity case was evaluated where it was 

assumed that all new E85 facilities would install 3 

pumps with 6 refueling positions. The cost per 

facility under this sensitivity case is $166,000. 200 40 CFR 280.32 requires that underground 

storage tank systems must be made of or lined with 

materials that are compatible with the substance 

stored in the system. 201Underwriters Laboratories recently finalized 

their requirements for the certification of E85 

compatible equipment. No certifications have been 

completed to date, because of the time needed to 

complete the application for certification including 

necessary testing. 

202All retail dispenser components except the 

hose that connects the nozzle to the dispenser have 

been evaluated by UL. Once such hoses have been 

evaluated by UL, a certification for the complete 

fuel dispenser assembly may be finalized by UL. 

203E85 facility costs were amortized over 15 years 

at 7% and the costs spread over the projected 

volume of E85 dispensed. 

204 Gasohol, a fuel containing at least 10% 

biomass-derived ethanol, received a partial 

exemption from the federal gasoline excise tax. This 

exemption was implemented in 1979 and a 

blender’s tax credit and a pure alcohol fuel credit 

were added to the mix in 1980. 

A significant challenge facing 

terminals and one that is currently 

limiting the volume of ethanol that can 

be used is the ability to receive ethanol 

by rail. Only a small fraction of 

petroleum terminals currently have rail 

receipt capability and a number likely 

have space constraints or are located too 

far from the rail system which prevents 

the installation of such capability. The 

trend to locate ethanol unit train 

destinations at rail terminals will help 

to alleviate these concerns. Petroleum 

terminals within trucking distance of 

each other are also likely to cooperate so 

that only one would need to install rail 

receipt capability. Given the timeframe 

during which the projected volumes of 

ethanol ramp up, we believe that these 

means can be utilized to ensure that a 

sufficient number of terminals have 

access to ethanol shipped by rail 

although some will need to rely on 

secondary shipment by truck from large 

ethanol hub receipt facilities. We 

request comment on the current rail 

receipt capability at terminals and the 

extent to which petroleum terminals can 

be expected to install such capability. 

Comment is also requested on the extent 

to which the installation of ethanol 

receipt facilities at rail terminals can 

help to meet the need to bring ethanol 

by rail to petroleum terminals. Our 

current analysis estimated that half of 

the new ethanol rail receipt capability 

needed to support the use of the 

projected ethanol volumes under the 

EISA would be installed at petroleum 

terminals, and half would be installed at 

rail terminals. A recently completed 

study by ORNL estimated that all new 

ethanol rail receipt capability would be 

installed at existing rail terminals given 

the limited ability to install such 

capability at petroleum terminals.195 We 

intend to review our estimates regarding 

the location of the additional ethanol 

rail receipt facilities for the final rule in 

light of the ORNL study. 

9. Need for Additional E85 Retail 

Facilities 

We estimate that an additional 24,250 

E85 retail facilities would be needed to 

facilitate the consumption of the 

additional amount of ethanol that we 

project would be used by 2022 in 

response to the requirements under the 

RFS2 standards.196 On average, this 

equates to approximately 1,960 new E85 

facilities that would need to be added 

each year from 2009 through 2022 in 

order to satisfy this goal. This is a very 

ambitious timeline given that there are 

less than 2,000 E85 retail facilities in 

service today. Nevertheless, we believe 

the addition of these numbers of new 

E85 facilities may be possible for the 

industries that manufacture and install 

E85 retail equipment. Underwriters 

Laboratories recently finalized its 

certification requirements for E85 retail 

equipment.197 Equipment manufactures 

are currently evaluating the changes that 

will be needed to meet these 

requirements.198 However, we 

anticipate the needed changes will not 

substantially increase the difficulty in 

the manufacture of such equipment 

compared to equipment which is 

specifically manufactured for 

dispensing E85 today. 

We estimate that the cost of installing 

E85 refueling equipment will average 

$122,000 per facility which equates to 

$3 billion by 2022.199 These costs 

include the installation of an 

underground storage tank, piping, 

dispensers, leak detection, and other 

ancillary equipment that is compatible 

with E85.200 Our E85 facility cost 

estimates are based on input from fuel 

retailers and other parties with 

familiarity in installing E85 compatible 

equipment. We understand that a 

certification has yet to be finalized by 

Underwriters Laboratories for a 

complete equipment package necessary 

to store/dispense E85 at a retail 

facility.201 Thus, there is some 

uncertainty regarding the type of 

equipment that will be needed for 

compliance with the E85 equipment 

certification requirements, and the 

associated costs. Nevertheless, we 

believe that the E85 equipment that is 

eventually certified for use will not be 

substantially different from that on 

which our cost estimates are based.202

Petroleum retailers expressed 

concerns about their ability to bear the 

cost installing the needed E85 refueling 

equipment. Today’s proposal does not 

contain a requirement for retailers to 

carry E85. We understand that retailers 

will only install E85 facilities if it is 

economically advantageous for them to 

do so and that they will price their E85 

and E10 in a manner to recover these 

costs. While the $3 billion total cost for 

E85 refueling facilities is a substantial 

sum, it equates to just 1.5 cents per 

gallon of E85 throughput.203 Therefore, 

we do not believe that the cost of 

installing E85 refueling equipment will 

represent an undue burden to retailers 

given the very large projected consumer 

demand for E85. 

Petroleum retailers also expressed 

concern regarding their ability to 

discount the price of E85 sufficiently to 

persuade flexible fuel vehicle owners to 

choose E85 given the lower energy 

density of ethanol. This issue is 

discussed in Section V.D.2.e. of today’s 

preamble. 

D. Ethanol Consumption 

1. Historic/Current Ethanol 

Consumption 

Ethanol and ethanol-gasoline blends 

have a long history as automotive fuels. 

However, cheap gasoline/blendstocks 

kept ethanol from making a significant 

presence in the transportation sector 

until the end of the 20th century when 

environmental regulations and tax 

incentives helped to stimulate growth. 

In 1978, the U.S. passed the Energy 

Tax Act which provided an excise tax 

exemption for ethanol blended into 

gasoline that would later be modified 

through subsequent regulations.204 In 

the 1980s, EPA initiated a phase-out of 

leaded gasoline which created some 

interest in ethanol as a gasoline 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25009 

204 Gasohol, a fuel containing at least 10% 

biomass-derived ethanol, received a partial 

exemption from the federal gasoline excise tax. This 

exemption was implemented in 1979 and a 

blender’s tax credit and a pure alcohol fuel credit 

were added to the mix in 1980. 205The 2008 Farm Bill, discussed in more detail 

in Section V.B.2.b, replaces the $0.51/gal ethanol 

blender credit with a $0.45/gal corn ethanol blender 

credit and also introduces a $1.01/gal cellulosic 

biofuel producer credit. Both credits are effective 

January 1, 2009. 

206Based on 2004 Federal Highway Association 

(FHWA) State Gasohol Report less estimated RFG 

and oxyfuel ethanol usage based on EPA’s 2004 

RFG Fuel Survey results and knowledge of state 

oxyfuel programs and fuel oxygenates. For more on 

historical ethanol usage by state and fuel type, refer 

to Section 1.7.1.1 of the DRIA. 

207Source: June 23, 2008 Federal Times, Special 

Report: Fleet Management. 

208Source: DOE Energy Efficiency and Renewable 

Energy (worksheet available at 

www.eere.energy.gov/afdc/data/index.html.) 

209Source: EIA Annual Energy Outlook 2007, 

Table 17. 

210For more information on distribution 

accommodations, refer to Section V.C. 

oxygenate. Upon passage of the 1990 

CAA amendments, states implemented 

winter oxygenated fuel (‘‘oxyfuel’’) 

programs to monitor carbon monoxide 

emissions. EPA also established the 

reformulated gasoline (RFG) program to 

help reduce emissions of smog-forming 

and toxic pollutants. Both the oxyfuel 

and RFG programs called for oxygenated 

gasoline. However, petroleum-derived 

ethers, namely methyl tertiary butyl 

ether (MTBE), dominated oxygenate use 

until drinking water contamination 

concerns prompted a switch to ethanol. 

Additional support came in 2004 with 

the passage of the Volumetric Ethanol 

Excise Tax Credit (VEETC). The VEETC 

provided domestic ethanol blenders 

with a $0.51/gal tax credit, replacing the 

patchwork of existing subsidies.205 The 

phase-out of MTBE and the introduction 

of the VEETC along with state mandates 

and tax incentives created a growing 

demand for ethanol that surpassed the 

traditional oxyfuel and RFG markets. By 

the end of 2004, not only was ethanol 

the lead oxygenate, it was found to be 

blended into a growing number of 

states’ conventional gasoline.206

In the years that followed, rising 

crude oil prices and other favorable 

market conditions continued to drive 

ethanol usage. In May 2007, EPA 

promulgated a Renewable Fuel Standard 

(‘‘RFS1’’) in response to EPAct. The 

RFS1 program set a floor for renewable 

fuel use reaching 7.5 billion gallons by 

2012, the majority of which was 

ethanol. The country is currently on 

track for exceeding the RFS1 

requirements and meeting the 

introductory years of today’s proposed 

RFS2 program. For a summary of the 

growth in U.S. ethanol usage over the 

past decade, refer to Table V.D.1.–1. 

TABLE V.D.1–1—U.S. ETHANOL

CONSUMPTION (INCLUDING IMPORTS) 

Year 

Total ethanol use a

Trillion BTU Bgal 

1999 .................. 120 1.4 

2000 .................. 138 1.6 

2001 .................. 144 1.7 

2002 .................. 171 2.0 

2003 .................. 233 2.8 

2004 .................. 292 3.5 

2005 .................. 334 4.0 

2006 .................. 451 5.3 

2007 .................. 566 6.7 

2008 .................. 792 9.4 

aEIA Monthly Energy Review March 2009 

(Table 10.2). 

Through the years, there have also 

been several policy initiatives to 

increase the number of flexible fuel 

vehicles (FFVs) capable of consuming 

up to 85 volume percent ethanol blends 

(E85). The Alternative Motor Vehicle 

Fuels Act of 1988 provided automakers 

with Corporate Average Fuel Economy 

(CAFE) credits for producing 

alternative-fuel vehicles, including 

FFVs as well as CNG and propane 

vehicles. Furthermore, the Energy 

Policy Act of 1992 required government 

fleets to begin purchasing alternativefuel vehicles, and the majority of fleets 

chose FFVs.207 As a result of these two 

policy measures, there are over 7 

million FFVs on the road today.208

These vehicles increase our nation’s 

ethanol consumption potential beyond 

what is capable with conventional 

vehicles. However, most FFVs are 

currently refueling on conventional 

gasoline (E0 or E10) due to limited E85 

availability and the fact that E85 is 

typically priced 20–30 cents per gallon 

higher than gasoline on an energy 

equivalent basis. As such, we are not 

currently tapping into the full ethanol 

consumption potential of our FFV fleet. 

However, we expect refueling patterns 

to change in the future under the RFS2 

program. 

2. Increased Ethanol Use under RFS2 

To meet the RFS2 standards, ethanol 

consumption will need to be much 

higher than both today’s levels and 

those projected to occur absent RFS2. 

The Energy Information Administration 

(EIA) projected that under business-asusual conditions, ethanol usage would 

grow to just over 13 billion gallons by 

2022.209 This represents significant 

growth from today’s usage, however, 

this volume of ethanol is capable of 

being consumed by today’s vehicle fleet 

albeit with some fuel infrastructure 

improvements.210 Although EIA 

projected a small percentage of ethanol 

to be blended as E85 in 2022, 13 billion 

gallons of ethanol could also be 

consumed by displacing about 90% of 

our country’s forecasted gasoline energy 

demand with E10. The maximum 

amount of ethanol our country is 

capable of consuming as E10 compared 

to the projected RFS2 ethanol volumes 

is shown below in Figure V.D.2–1.211

25010 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

211The maximum E10 volumes are a function of 

the gasoline energy demand reported in EIA’s 

Annual Energy Outlook 2009, Table 2 adjusted with 

lower heating values. 

213For consideration of other biofuels, refer to 

Section V.D.3.d. 

As shown in Figure V.D.2–1, under 

the proposed RFS2 program, we are 

projected to hit the E10 ‘‘blend wall’’ of 

about 14.5 billion gallons of ethanol by 

2013. This volume corresponds to 100% 

E10 nationwide. However, if gasoline 

demand falls, or if E10 cannot get 

distributed nationwide, the nation could 

hit the blend wall sooner. Regardless, to 

get beyond the blend wall and consume 

more than 14–15 billion gallons of 

ethanol, we are going to need to see 

significant increases in the number 

FFVs on the road, the number of E85 

retailers, and the FFV E85 refueling 

frequency. In the subsections that 

follow, we will highlight the variables 

that impact our nation’s ethanol 

consumption potential and, more 

specifically, what measures the market 

may need to take in order to consume 

34 billion gallons of ethanol by 2022 

(assuming the cellulosic biofuel 

standard and the majority of the 

advanced biofuel standard are met with 

ethanol). 

As explained in Section V.A.2, our 

primary RFS2 analysis focuses on 

ethanol as the main biofuel in the 

future.213 In addition, from an ethanol 

consumption standpoint, we have 

focused on an E10/E85 world. While E0 

is capable of co-existing with E10 and 

E85 for a while, we assumed that E10 

would replace E0 as expeditiously as 

possible and that all subsequent ethanol 

growth would come from E85. 

Furthermore, for our primary analysis, 

we assumed that no ethanol 

consumption would come from the midlevel ethanol blends (i.e., E15 or E20) as 

they are not currently approved for use 

in non-FFVs. However, in Section V.D.3 

below, we discuss the potential 

approval pathways for mid-level ethanol 

blends and the volume implications. 

We acknowledge that, if approved, 

mid-level ethanol blends could help the 

nation meet the proposed RFS2 volume 

requirements. First, non-FFVs could 

consume more ethanol per gallon of 

‘‘gasoline’’. This could result in greater 

ethanol consumption nationwide. In 

addition, mid-level blends could allow 

gasoline retailers to continue to price 

ethanol relative to gasoline (as it 

currently is for E10). For these reasons, 

it is possible that mid-level ethanol 

blends could help the nation get beyond 

the E10 blend wall. However, as 

explained in Section V.D.3.b, there are 

numerous actions that would need to be 

taken to bring mid-level ethanol blends 

to market. In addition, mid-level ethanol 

blends alone (even if made available 

nationwide) are not capable of fulfilling 

the RFS2 requirements in later years. 

We would essentially hit another blend 

wall 1–6 years later depending on the 

intermediate blend, how quickly it 

could be brought to market, and how 

widely mid-level ethanol blends were 

distributed at retail stations nationwide. 

Nevertheless, this time could be very 

valuable when it comes to expanding 

E85/FFV infrastructure and/or 

commercializing other non-ethanol 

cellulosic biofuels. 

Regardless, our primary analysis 

focuses on an E10/E85 world because 

mid-level ethanol blends are not 

currently approved for use in 

conventional gasoline vehicles and 

nonroad equipment. Before usage could 

be legalized, as discussed more in 

Section V.D.3 below, EPA would need 

to grant a waiver declaring that midlevel blends are substantially similar or 

‘‘sub-sim’’ to gasoline or perhaps even 

reinterpret the meaning of ‘‘sub-sim’’. 

While such a waiver has not yet been 

granted, several organizations/agencies 

are performing vehicle emission testing 

and investigating other impacts of midVerDate Nov<24>2008 22:05 May 22, 2009 Jkt 217001 PO 00000 Frm 00108 Fmt 4701 Sfmt 4702 E:\FR\FM\26MYP2.SGM 26MYP2

EP26MY09.006</GPH>
Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25011 

214For more information on mid-level ethanol 

blends testing, refer to Section V.D.3.b. 

215For blend wall discussions, we rely on the 

most recent AEO 2009 projections. However for our 

detailed ethanol consumption analysis presented in 

this section (and in more detail in Section 1.7.1 of 

the DRIA), we relied on AEO 2008. 

216EIA Annual Energy Outlook 2007 & 2008, 

Table 2. 

217For more information on gasoline energy 

projections, refer to Section 1.7.1.2.1 of the DRIA. 

218 DOE Energy Efficiency and Renewable Energy 

August 2008 estimate (worksheet available at 

www.eere.energy.gov/afdc/data/index.html). 

219For more on the FFV production scenarios we 

considered, refer to Section 1.7.1.2.2 of the DRIA. 

220Ethanol Producer Magazine, ‘‘View From the 

Hill.’’ July 2007. 

221Ethanol Producer Magazine, ‘‘Automakers 

Maintain FFV Targets in Bailout Plans.’’ February 

2009. 

222NEVC 2008 Purchasing Guide for Flexible 

Fuel Vehicles. 

223Several of the FFV assumptions may need to 

be revised for the FRM in light of recent events. 

224 Ibid. 

225NEVC FYI Newsletter: Volume 15, Issue 5: 

March 9, 2009. 

226Based on National Petroleum News gasoline 

station estimate of 161,768 in 2008. 

227For a more detailed discussion on how we 

derived our one-in-four reasonable access 

assumption, refer to Section 1.6 of the DRIA. For 

the distribution cost implications as well as the cost 

impacts of assuming reasonable access is greater 

than one-in-four pumps, refer to Section 4.2 of the 

DRIA. 

228Computed as percent of stations with E85 

(1,963/161,768 as of March 2009 or 1,251/164,292 

as of July 2007) divided by 25% (one-in-four 

stations). 

229The following states have adopted the plan: 

Indiana, Kansas, Michigan, Minnesota, Ohio, South 

Dakota, Wisconsin, Iowa, and most recently, North 

Dakota. For more information, visit: http:// 

Continued 

level blends.214 Therefore, as a 

sensitivity analysis, we have analyzed 

what might need to be done to bring 

mid-level ethanol blends to market 

(should a sub-sim waiver be approved) 

and the extent to which such blends 

could help our nation meet the RFS2 

ethanol standards, at least in the near 

term. Finally we end our ethanol usage 

discussion by looking at other strategies 

for getting beyond the E10 blend wall. 

a. Projected Gasoline Energy Demand 

The maximum amount of ethanol our 

country is capable of consuming in any 

given year is a function of the total 

gasoline energy demanded by the 

transportation sector. Our nation’s 

gasoline energy demand is dependent 

on the number of gasoline-powered 

vehicles on the road, their average fuel 

economy, vehicle miles traveled (VMT), 

and driving patterns. For analysis 

purposes, we relied on the gasoline 

energy projections reported by EIA in 

AEO 2008.215 Unlike AEO 2007, AEO 

2008 takes the fuel economy 

improvements set by EISA into 

consideration and also assumes a slight 

dieselization of the vehicle fleet. The 

result is a 15% reduction in the 

projected 2022 gasoline energy demand 

from AEO 2007 to AEO 2008.216 EIA 

basically has gasoline energy demand 

(petroleum-based gasoline plus ethanol) 

flattening out, and even slightly 

decreasing, as we move into the future 

and implement the EISA vehicle 

standards.217

b. Projected Growth in Flexible Fuel 

Vehicles 

According to DOE’s Department of 

Energy Efficiency and Renewable 

Energy, there are currently over 7 

million FFVs on the road today capable 

of consuming E85.218 And that number 

is growing steadily. Automakers are 

incorporating more and more FFVs into 

their light-duty production plans. While 

the FFV system (i.e., fuel tank, sensor, 

delivery system, etc.) used to be an 

option on some vehicles, most FFV 

producers are moving in the direction of 

converting entire product lines over to 

E85-capable systems. Still, the number 

of FFVs that will be manufactured and 

purchased in future years is uncertain. 

For our cost analysis, we examined 

several different FFV production 

scenarios. But for our ethanol usage 

analysis, we focused on one primary 

FFV scenario, described in more detail 

below.219

In response to President Bush’s ‘‘20- 

in-10’’ plan of reducing American 

gasoline usage by 20% in 10 years, 

domestic automakers responded with 

aggressive FFV production goals. 

General Motors, Ford and Chrysler 

(referred to hereafter as ‘‘The Detroit 3’’) 

announced plans to produce 50% FFVs 

by 2012.220 And despite the current 

state of the economy and the auto 

industry, it appears U.S. automakers are 

still moving forward with their FFV 

production plans.221 Assuming that The 

Detroit 3 continue to maintain 50% 

market share and that total vehicle sales 

remain around 16 million per year, at 

least 4 million FFVs will be produced 

by the 2012 model year. Based on 2008 

offerings, we assumed that 

approximately 80% of The Detroit 3’s 

FFV production commitment would be 

met by light-duty trucks and the 

remaining 20% would be cars.222 223 We 

also assumed that all the FFVs in 

existence today were produced by The 

Detroit 3 (and therefore share the same 

aforementioned car/truck ratio) and that 

production would ramp up linearly 

beginning in 2008 to reach the 2012 

commitment. 

Although non-domestic automakers 

have not made any official FFV 

production commitments, Nissan, 

Mercedes, Izuzu, and Mazda all 

included at least one flexible fuel 

vehicle in their 2008 model year 

offerings.224 And we anticipate that 

additional FFVs (or FFV options) will be 

added in the future. Ultimately, we 

predict that non-domestic FFV 

production could be as high as 25%, or 

about 2 million FFVs per year. While we 

are not forecasting an official FFV 

production commitment from the nondomestic automakers, we believe that 

this represents an aggressive, yet 

reasonable FFV production estimate for 

analysis purposes. Furthermore, based 

on current offerings, we assumed that 

the majority of non-domestic FFV 

production would be trucks. With 

respect to timing, we expect that the 

non-domestic automakers would ramp 

up FFV production later than The 

Detroit 3. For analysis purposes, we 

assumed that non-domestic automakers 

would ramp up FFV production 

beginning in 2013, and like The Detroit 

3, it would take about five years for 

them to reach their FFV production 

goals (or in this case, the assumed 25% 

production level) 

Based on these FFV assumptions and 

forecasted vehicle phase-out, VMT, and 

fuel economy estimates provided by 

EPA’s MOVES Model, we calculate that 

the maximum percentage of fuel 

(gasoline/ethanol mix) that could 

feasibly be consumed by FFVs in 2022 

would be about 30%. For more 

information on our FFV analysis, refer 

to Section 1.7.1.2.2 of the DRIA. 

c. Projected Growth in E85 Access 

According to the National Ethanol 

Vehicle Coalition (NEVC), there are 

currently over 1,900 retailers offering 

E85 in 45 states plus the District of 

Columbia.225 While this represents 

significant industry growth, it still only 

translates to about 1% of U.S. retail 

stations nationwide carrying the fuel.226

As a result, most FFV owners clearly do 

not have reasonable access to E85. For 

our FFV/E85 analysis, we have defined 

‘‘reasonable access’’ as one-in-four 

pumps offering E85 in a given area.227

Accordingly, just over 4% of the nation 

currently has reasonable access to E85, 

up from 3% in 2007 (based on a midyear NEVC E85 pump estimate).228

There are a number of states 

promoting E85 usage by offering FFV/ 

E85 awareness programs and/or retail 

pump incentives. A growing number of 

states are also offering infrastructure 

grants to help expand E85 availability. 

Currently, nine Midwest states have 

adopted a progressive Energy Security 

and Climate Stewardship Platform.229

25012 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

www.midwesterngovernors.org/resolutions/ 

Platform.pdf. 

230A copy of House Rule 6734 can be accessed 

at: http://www.e85fuel.com/news/2008/ 

080108_shimkus_release/shimkus.pdf. 

231For this analysis, we’ve defined ‘‘urban’’ as the 

top 150 metropolitan statistical areas according to 

the U.S. census and/or counties with the highest 

VMT projections according the EPA MOVES model, 

all RFG areas, winter oxy-fuel areas, low-RVP areas, 

and other relatively populated cities in the 

Midwest. 

232Based on the assumption that FFV owners 

travel approximately 12,000 miles per year and get 

about 18 miles per gallon on average under actual 

in-use driving conditions. For more information, 

refer to Section 1.7.1.2.4 of the DRIA. 

233EIA Annual Energy Outlook 2009, Table 17. 

234NEVC, ‘‘2008 Purchasing Guide for Flexible 

Fuel Vehicles.’’ Refers to all mass produced 3.5 and 

3.9L Impalas. However, it is our understanding that 

consumers may still place special orders for nonFFVs. 

235Based on our assumption that denatured 

ethanol has an average lower heating value of 

77,930 BTU/gal and conventional gasoline (E0) has 

average lower heating value of 115,000 BTU/gal. 

For analysis purposes, E10 was assumed to contain 

10 vol% ethanol and 90 vol% gasoline. Based on 

EIA’s AEO 2008 report, E85 was assumed to contain 

74 vol% ethanol and 26 vol% gasoline on average. 

236Based on average E85 and regular unleaded 

gasoline prices reported at http:// 

www.fuelgaugereport.com/ on April 23, 2009. 

237The government-mandated gasoline ethanol 

content was 25% as of July 2007. Source: F.O. Licht 

World Ethanol & Biofuels Report Vol. 5 No. 21 July 

9, 2007. 

The platform includes a Regional 

Biofuels Promotion Plan with a goal of 

making E85 available at one third of all 

stations by 2025. In addition, on July 31, 

2008, Congresswoman Stephanie 

Herseth Sandlin (D–SD) and John 

Shimkus (R–IL) introduced The E85 and 

Biodiesel Access Act that would amend 

IRS tax code and increase the existing 

federal income tax credit from $30,000 

or 30% of the total cost of 

improvements to $100,000 or 50% of 

the total cost of needed alternative fuel 

equipment and dispensing 

improvements.230 While not signed into 

law, such a tax credit could provide a 

significant retail incentive to expand 

E85 infrastructure. 

Given the growing number of state 

infrastructure incentives and the 

proposed Federal alternative fuel 

infrastructure subsidy, it is clear that 

E85 infrastructure will continue to 

expand in the future. However, the 

extent to which nationwide E85 access 

will grow is difficult to predict, let alone 

quantify. For analysis purposes, as a 

practical upper bound, we have selected 

70% by 2022. This is roughly equivalent 

to all urban areas in the United States 

offering reasonable (one-in-four-station) 

access to E85.231 We are not concluding 

that the percentage of the nation with 

reasonable access to E85 could not 

exceed 70% (as a sensitivity, we also 

modeled the cost impacts of nationwide 

access to E85) or that availability would 

necessarily be concentrated in urban 

areas. However, for analysis purposes, 

we believe that 70% is a good surrogate 

for a practical portion of the country 

that could have reasonable one-in-four 

access to E85 by 2022 under the 

proposed RFS2 program. On average, 

this translates to about 18% of retail 

stations nationwide offering E85. As 

discussed in Section V.C, we believe 

this is feasible based on our assessment 

of the distribution infrastructure 

capabilities. For more information on 

the projected growth in E85 access, refer 

to Section 1.7.1.2.3 of the DRIA. 

d. Required Increase in E85 Refueling 

Rates 

As mentioned above, there were 

approximately 7 million FFVs on the 

road in 2008. If all FFVs refueled on E85 

100% of the time, this would translate 

to about 6.5 billion gallons of E85 

use.232 However, E85 usage was only 

around 12 million gallons in 2008.233

This means that, on average, FFV 

owners were only tapping into about 

0.2% of their vehicles’ E85/ethanol 

usage potential last year. Assuming that 

only 4% of the nation had reasonable 

one-in-four access to E85 in 2008 (as 

discussed above), this equates to an 

estimated 5% E85 refueling frequency 

for those FFVs that had reasonable 

access to the fuel. 

There are several reasons for today’s 

low E85 refueling frequency. For 

starters, many FFV owners may not 

know they are driving a vehicle that is 

capable of handling E85. As mentioned 

earlier, more and more automakers are 

starting to produce FFVs by engine/ 

product line, e.g., all 2008 Chevy 

Impalas are FFVs.234 Consequently, 

consumers (especially brand loyal 

consumers) may inadvertently buy a 

flexible fuel vehicle without making a 

conscious decision to do so. And 

without effective consumer awareness 

programs in place, these FFV owners 

may never think to refuel on E85. In 

addition, FFV owners with reasonable 

access to E85 and knowledge of their 

vehicle’s E85 capabilities may still not 

choose to refuel on E85. They may feel 

inconvenienced by the increased E85 

refueling requirements. Based on its 

lower energy density, FFV owners will 

need to stop to refuel 21% more often 

when filling up on E85 over E10 (and 

likewise, 24% more often when 

refueling on E85 over conventional 

gasoline).235 In addition, some FFV 

owners may be deterred from refueling 

on E85 out of fear of reduced vehicle 

performance or just plain unfamiliarity 

with the new motor vehicle fuel. 

However, as we move into the future, 

we believe the biggest determinant will 

be price—whether E85 is priced 

competitively with gasoline based on its 

reduced energy density and the fact that 

you need to stop more often, drive a 

little further to find an E85 station, and 

depending on the retail configuration, 

wait in longer lines to fill up on E85. 

To comply with the proposed RFS2 

program and consume 34 billion gallons 

of ethanol by 2022, not only would we 

need more FFVs and more E85 retailers, 

we would need to see a significant 

increase in the current FFV E85 

refueling frequency. Based on the FFV 

and retail assumptions described above 

in subsections (b) and (c), our analysis 

suggests that FFV owners with 

reasonable access to E85 in 2022 would 

need to fill up on it 74% of the time, 

a significant increase from today’s 

estimated 5% refueling frequency. Were 

there to be fewer FFVs in the fleet, the 

E85 refueling frequency would need to 

be even higher. Similarly, with more 

FFVs in the fleet, the E85 refueling 

frequency could be lower and still meet 

the proposed RFS2 requirements. 

However, even with an FFV mandate, 

our analysis suggests that we would 

need to see an increase from today’s 

average FFV E85 refueling frequency. In 

order for this to be possible, there will 

need to be an improvement in the 

current E85/gasoline price relationship. 

e. Market Pricing of E85 Versus Gasoline 

According to a recent online fuel 

price survey, E85 is currently priced 

almost 30 cents per gallon higher than 

conventional gasoline on an energyequivalent basis.236 To increase our 

nation’s E85 refueling frequency to the 

levels described above, E85 needs to be 

priced competitively with (if not lower 

than) conventional gasoline based on its 

reduced energy content, increased time 

spent at the pump, and limited 

availability. Our analysis, described in 

more detail in Section 1.7.1.2.5 of the 

DRIA, suggests that E85 would need to 

be priced about one-third lower than 

gasoline at retail (based on 2006 prices) 

in order for it to be cost-competitive. As 

expected, higher crude prices could 

make E85 look slightly more attractive 

while lower crude oil prices could make 

E85 look less attractive. 

In Brazil, charts are posted at gas 

stations informing flex-fuel vehicle 

owners whether it makes sense to fill up 

on ‘‘gasoline’’ (containing 20–25% 

denatured anhydrous ethanol) 237 or 

‘‘alcohol’’ (100% denatured hydrous 

ethanol) based on the price and relative 

energy density of each. However, in the 

U.S., FFV owners will likely be on their 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25013 

238Source: The American Petroleum Institute July 

2008 Gasoline Tax Report available at: http:// 

www.api.org/statistics/fueltaxes/upload/July_2008_

gasoline_and_diesel_summary_pages.pdf. 

239Source: DOE Energy Efficiency and Renewable 

Energy Web site (http://www.eere.energy.gov/). 

240Refer to Senate Bill 3303 which can be found 

at: http://thomas.loc.gov/cgi-bin/query/ 

z?c110:S.3303. 

241Refer to House Rule 6559 which can be found 

at: http://thomas.loc.gov/cgi-bin/bdquery/ 

z?d110:H.R.6559. 

own for figuring out which fuel is more 

economical. 

Although in some areas of the country 

E85 is already priced significantly lower 

than gasoline, this is a far cry from a 

nationwide trend. And as we move into 

the future and incorporate cellulosic 

ethanol (a fuel that is currently more 

expensive to produce than corn 

ethanol), it may be even more difficult 

to produce ethanol for a price that the 

market would accept. However, a 

number of measures could be taken to 

help encourage FFV E85 refueling. 

The first is increased consumer 

awareness. To maximize ethanol usage, 

it is important that FFV owners are 

aware of their vehicle’s fueling 

capabilities, i.e., that their vehicle is 

capable of refueling on E85. It is equally 

important that FFV owners are aware of 

E85 refueling outlets that may be 

available to them. Automakers and/or 

car dealerships could notify FFV owners 

of E85 stations in their area. Together, 

increased automaker and retail 

awareness could help increase our 

nation’s E85 throughput potential. 

However, in order for consumers to 

actually choose E85 over conventional 

gasoline on a regular basis, there needs 

to be a marked price incentive at the 

pump. 

Current federal and most state tax 

code does not differentiate between 

ethanol sold as E10 and as E85. As of 

July 2008, state excise taxes were 

reported to account for more than $0.18 

per gallon of gasoline (on average).238

However, there are a number of states 

(e.g., Illinois, Indiana, North Dakota, 

and South Dakota) that currently waive 

or discount excise taxes on E85. This 

type of fuel tax structure helps 

contribute to a retail price relationship 

that favors E85 over conventional 

gasoline.239 If states continue to waive/ 

reduce E85 fuel taxes under RFS2, this 

could help increase the FFV E85 

refueling frequency. As expected, this 

would have the greatest impact on 

ethanol consumption in the areas of the 

country with the most FFVs. 

The E10/E85 price relationship could 

also be modified by the refining 

industry. Under the proposed program, 

gasoline refiners (as well as importers) 

would be required to purchase RINs to 

demonstrate that sufficient volumes of 

renewable/alternative fuels were used to 

meet their volume obligations. This 

could provide an incentive for these 

parties to take the steps necessary to 

ensure adequate ethanol use levels to 

facilitate compliance. One potential 

action that refiners might take to ensure 

a sufficient RIN supply would be to 

subsidize the price of the ethanol used 

to manufacture E85. Such a subsidy 

might be financed by an increase in 

their selling price of gasoline. In 

addition, refiners with marketing arms 

could adjust the retail price relationship 

of E10 in E85 in way that encourages 

E85 throughput while still maintaining 

the same average net profit. However, a 

relatively small proportion of refiners 

market their own gasoline and thus have 

the ability to make retail price 

adjustments. Consequently, relying 

solely on market mechanisms may 

create some competitive concerns. We 

request comment on viable and 

cooperative ways refiners and gasoline 

retailers could promote E85 throughput 

to meet the proposed RFS2 

requirements. 

3. Other Mechanisms for Getting 

Beyond the E10 Blend Wall 

a. Mandate for FFV Production 

One way to increase ethanol usage 

under RFS2 would be if there were more 

FFVs in the fleet. As described above, 

our primary analysis is based on the 

assumption that The Detroit 3 would 

follow through with their commitment 

to produce 50% FFVs by 2012 and the 

non-domestic automakers would ramp 

up FFV production beginning in 2013 

and produce 25% FFVs by 2017. Based 

on the projected number of FFVs in the 

fleet (and our E85 infrastructure growth 

assumptions), FFV owners with 

reasonable one-in-four access to E85 

would need to refuel on it 74% of the 

time. To achieve this optimistic 

refueling frequency, we believe there 

would need to be significant 

improvements to the E10/E85 price 

relationship. 

One way to reduce the required FFV 

E85 refueling frequency (and in turn 

decrease some of the pressure off E85 

prices) would be to further increase the 

number of FFVs in the fleet. While EPA 

does not have the authority to require 

automakers to produce FFVs, there are 

a number of bills in Congress that are set 

out to do just that. On July 22, 2008 

Senator Sam Brownback (R–KS) on 

behalf of himself and Senators Susan 

Collins (R–ME), Joseph Lieberman (I– 

CT), Ken Salazar (D–CO), and John 

Thune (R–SD) introduced the Open Fuel 

Standard Act of 2008, a bill that calls for 

50% of the U.S. vehicle fleet to be FFVs 

capable of using high blends of ethanol 

or methanol (in addition to gasoline) by 

2012. This number would grow to 80% 

by 2015.240 A similar FFV bill was 

introduced by Eliot Engel (D–NY) in the 

House on July 22, 2008.241

Since a future congressional mandate 

on FFV production in being discussed, 

we have modeled the impact that such 

a mandate could have on the RFS2 

program. For our sensitivity analysis, 

we found that if automakers were 

required to make all light-duty vehicles 

E85-capable by 2015 (and our same E85 

infrastructure growth assumptions 

applied), FFV owners with reasonable 

one-in-four access to E85 would only 

need to refuel on it 33% of the time. 

This represents a smaller increase from 

today’s estimated 5% refueling rate. 

However, implementing such a FFV 

mandate would have significant cost 

implications on the auto industry and 

would still not provide certainty that 

FFV owners would fuel on E85. For 

more information on this analysis, as 

well as other FFV production scenarios 

we considered, refer to Section 1.7.1.2.2 

of the DRIA. 

b. Waiver of Mid-Level Ethanol Blends 

(E15/E20) 

For our primary ethanol usage 

analysis, we considered that there 

would only be two fuels in the future, 

E10 and E85. And as explained in 

Section V.D.2, we believe it is feasible 

to consume 34 billion gallons of ethanol 

by 2022 given growth in FFV 

production and E85 availability and 

projected improvements in the current 

E10/E85 price relationship. 

However, several organizations and 

government entities are interested in 

increasing the concentration of ethanol 

beyond the current 10% limit in the 

commercial gasoline pool. Section 

211(f)(1) of the Clean Air Act prohibits 

the introduction into commerce, or 

increase in the concentration in use of, 

gasoline or gasoline additives for use in 

motor vehicles unless they are 

substantially similar to the gasoline or 

gasoline additives used in the 

certification of new motor vehicles or 

motor vehicle engines. EPA may grant a 

waiver of this prohibition under Section 

211(f)(4) provided that the fuel or fuel 

additive ‘‘will not cause or contribute to 

a failure of any emission control device 

or system (over the useful life of the 

motor vehicle, motor vehicle engine, 

nonroad engine or nonroad vehicle in 

which the device or system is used) to 

achieve compliance by the vehicle or 

engine with the emission standards to 

25014 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

242 73 FR 22277 (April 25, 2008). 243 Gas Plus, Inc. submitted an application for a 

211(f)(4) waiver for E10 which was granted, see 44 

FR 20777 (April 6, 1979). 244EPA has expressed what such a waiver testing 

program might look like, see Karl Simon, ‘‘Mid 

Level Ethanol Blend Experimental Framework: Epa 

Staff Recommendations,’’ June 2008, and Ed Nam 

‘‘Vehicle Selection & Sample Size Issues for 

Catalyst and Evap Durability Testing,’’ November 

2008, in the docket (EPA–HQ–OAR–2005–0161). 

245Effects of Intermediate Ethanol Blends on 

Legacy Vehicles and Small Non-Road Engines, 

Report 1, Prepared by Oak Ridge National 

Laboratory for the Department of Energy, October 

2008. 

246Results for other cases are discussed in 

Section 1.7.1.3 of the DRIA. 

which it has been certified.’’ The most 

recent ‘‘substantially similar’’ 

interpretive rule for unleaded gasoline 

presently allows oxygen content up to 

2.7% by weight for certain ethers and 

alcohols.242 E10 contains approximately 

3.5% oxygen by weight, which makes a 

gasoline-ethanol blend with ten% 

ethanol not ‘‘substantially similar’’ to 

certification fuel under the current 

interpretation.243 Since any mid-level 

blend would have a greater than 

allowed oxygen content, any mid-level 

blend would need to have a waiver 

under Section 211(f)(4) of the CAA in 

order to be sold commercially. 

Before EPA grants a 211(f)(4) waiver 

for a new fuel or fuel additive, an 

applicant must prove that the new fuel 

or fuel additive will meet the waiver 

requirements outlined in the statute. 

EPA has required that applicants 

provide vehicle/engine testing for 

tailpipe emissions, evaporative 

emissions, materials compatibility, and 

driveability. Testing needs to include 

emissions over the full useful life of 

vehicle and equipment. Several 

interested parties are investigating the 

impact that mid-level ethanol blends 

(e.g., E15 or E20) may have on these 

areas among others (i.e. catalyst, engine, 

and fuel system durability, and onboard 

diagnostics). In order to use the 

information collected for waiver 

application purposes, the mid-level 

ethanol blend testing will need to 

consider the different engines and fuel 

systems currently in service that could 

be exposed to mid-level ethanol blends 

and the long-term impact of using such 

blends.244 After receiving a waiver 

application, EPA must give public 

notice and comment and has 270 days 

to grant or deny the waiver request. 

The Department of Energy (DOE) has 

developed and initiated a 

comprehensive testing program to 

investigate the potential impacts of midlevel blends of ethanol. Initial testing 

was conducted on a limited number of 

high-volume vehicles and small nonroad engines and a preliminary report 

was published in October, 2008.245 In 

addition, DOE is in the process of 

leveraging existing EPA vehicle and 

small engine test programs (originally 

designed to test up to 10% ethanol) to 

add mid-level ethanol blends to the fuel 

matrix. DOE’s comprehensive test 

program is intended to evaluate a wide 

range of emission, performance, and 

durability issues associated with midlevel ethanol blends (additional reports 

forthcoming). 

DOE is not alone in pursuing midlevel blends. In 2005, the State of 

Minnesota, a large producer of corn 

ethanol, passed a law requiring that by 

2015, 20% of gasoline (by volume) must 

be replaced by ethanol. While this level 

could be achieved with a high 

percentage of E85 usage by FFVs, the 

state has also expressed an interest in 

moving to 20% ethanol blends. Several 

other states and organizations have also 

expressed interest in increasing ethanol 

use by adopting E15 or E20. The 

Renewable Fuels Association (RFA) and 

the American Coalition for Ethanol 

(ACE) have been working with various 

government entities to investigate the 

impact of mid-level blends 

On March 6, 2009, Growth Energy and 

54 ethanol manufacturers submitted an 

application for a waiver of the 

prohibition of the introduction into 

commerce of certain fuels and fuel 

additives set forth in section 211(f) of 

the Act. This application seeks a waiver 

for ethanol-gasoline blends of up to 15 

percent by volume ethanol. The statute 

directs the Administrator of EPA to 

grant or deny this application within 

270 days of receipt by EPA, in this 

instance December 1, 2009. EPA 

recently issued a federal register notice 

announcing receipt of the Growth 

Energy waiver application and soliciting 

comment on all aspects of it. Refer to 74 

FR 18228 (April 21, 2009). 

While the current Growth Energy 

waiver application is still under review, 

as a sensitivity, we considered the 

implications that adding E15 or E20 to 

the marketplace could have on ethanol 

usage and the supporting fuel 

infrastructure should such blends be 

permitted. For each case, we assumed 

that E10 would need to continue to 

remain in existence to meet the demand 

of legacy vehicle and non-road engine 

owners. This would also provide 

consumer choice. Experience in past 

fuel programs has shown that many 

consumers will not be comfortable 

refueling on higher ethanol blends and 

will blame any problems that may occur 

on the new fuel (regardless of the actual 

cause of the vehicle problems) causing 

a backlash against the new fuel 

requirements. Therefore, we believe it is 

critical to continue to allow consumers 

the choice between mid-level ethanol 

blends and conventional gasoline 

(assumed to be E10 in the future). 

For our optimistic mid-level ethanol 

blends scenario, we assumed that E15 or 

E20 could be available at all retail 

stations nationwide by the time the 

nation hits the E10 blend wall, or 

around 2013. This assumes a number of 

actions are taken to bring mid-level 

blends to market (explained in more 

detail below).246 We assumed that E10 

would be marketed as premium-grade 

gasoline, the mid-level ethanol blend 

(E15 or E20) would serve as regular, and 

like today, midgrade would be blended 

from the two fuels. Those vehicles and 

equipment which are unable to refuel 

on mid-level ethanol blends (or choose 

not to) could continue to fill up on E10. 

This mid-level ethanol blends scenario, 

described in more detail in Section 

1.7.1.3 of the DRIA, concluded that if 

mid-level ethanol blends were to be 

distributed at all retail stations 

nationwide, they could help increase 

ethanol usage to over 19 billion gallons 

(with E15) and 25 billion gallons (with 

E20). 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25015 

247 It may be possible for refiners to formulate a 

gasoline blendstock that would be suitable for 

manufacturing mid-level ethanol blends and E10 at 

the terminal. While this would avoid the logistical 

problems associated with maintaining separate 

blendstocks, there could be significant additional 

refining costs. 

248UL stated that they have data which indicates 

that the use of fuel dispensers certified for up to 

E10 blends to dispense blends up to a maximum 

ethanol content of 15 volume percent would not 

result in critical safety concerns (http:// 

www.ul.com/newsroom/newsrel/nr021909.html). 

Based on this, UL stated that it would support 

authorities having jurisdiction who decide to 

permit legacy equipment originally certified for up 

to E10 blends to be used to dispense up to 15 

volume percent ethanol. The UL announcement did 

address the compatibility of underground storage 

tank systems with greater than E10 blends. 

As shown in Figure V.D.2–2, in this 

optimistic phase-in scenario, adding 

E15 could postpone the blend wall by 

about three years to 2016 and adding 

E20 could postpone it another three 

years to 2019. Although mid-level 

ethanol blends will fall short of meeting 

the RFS2 requirements, they could 

provide interim relief while the county 

ramps up E85/FFV infrastructure and/or 

finds other non-ethanol alternatives 

(e.g., cellulosic diesel or biobutanol) to 

reach the RFS2 volumes. 

Our nation’s whole system of gasoline 

fuel regulation, fuel production, fuel 

distribution, and fuel use is built around 

gasoline with ethanol concentrations 

limited to E10. As a result, while a 

waiver may legalize the use of mid-level 

ethanol blends under the CAA, there are 

a number of other actions that would 

have to occur to bring mid-level blends 

to retail. The time needed to take these 

actions could delay the penetration of 

mid-level ethanol blends into the 

market. The CAA only provides a 1 

pound RVP waiver for ethanol blends of 

10 volume percent or less. Lacking such 

an RVP waiver, a special low-RVP 

gasoline blendstock would be needed at 

terminals to allow the formulation of 

mid-level ethanol blends that are 

complaint with EPA RVP requirements. 

Providing such a separate gasoline 

blendstock would present significant 

logistical challenges and costs to the 

fuel distribution system.247 A number of 

changes would be needed to EPA 

regulations including those pertaining 

to reformulated gasoline, anti-dumping, 

and gasoline deposit control additives to 

accommodate and mid-level ethanol 

blends. Such changes would need to be 

made through the notice and comment 

process similar to today’s action. In 

addition, most states require that fuel 

comply with the applicable ASTM 

International (formally known as the 

American Standards for Testing and 

Materials) specification. The 

development of an ASTM International 

specification for mid-level ethanol 

blends through an industry consensus 

process is currently being initiated. 

There are a number of requirements 

regarding the fire and leak protection 

safety of retail fuel dispensing and 

storage equipment. The Occupational 

Safety and Health Administration 

(OSHA) requires that retail fuel 

handling equipment be listed with an 

independent standards body such as 

Underwriters Laboratories (UL). No 

independent standards body has listed 

fuel handling equipment for mid-level 

ethanol blends. Furthermore, UL has 

stated that it would not expand listings 

for in-use fuel retail equipment 

originally listed for E10 blends to cover 

greater than E10 blends.248 EPA’s Office 

of Underground Storage Tanks (OUST) 

requires that UST systems must be 

compatible with the fuel stored in the 

system. These requirements pertain to 

all components of the system including 

the storage tank, connecting piping, 

pumps, seals and leak detection 

equipment. 

States typically adopt fire safety codes 

from either the National Fire Protection 

Association (NFPA) or the International 

Code Council (ICC). These organizations 

currently do not have provisions that 

would allow the mid-level ethanol 

blends to be stored/dispensed from 

existing equipment at retail. Local safety 

officials (e.g. fire marshals) referred to as 

‘‘Authorities Having Jurisdiction’’ 

(AHJ’s) often require a UL certification 

for fuel retail storage/dispensing 

equipment although some will accept 


EP26MY09.007</GPH>
25016 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

249As discussed previously, significant 

penetration of E85 is projected to be needed to 

facilitate the use of the volumes of ethanol we 

project would be needed to satisfy the requirements 

of the EISA. 

250See, for example, 53 FR 3636, February 8, 

1988, and 53 FR 33846, September 1, 1988. 

other substantiation of equipment safety 

such as a manufacture certification. Fuel 

retailers must also satisfy the 

requirements of the insurance company 

that they are insured through which 

may be more stringent than the legal 

requirements. Given the liability 

concerns associated with leaks from 

underground storage tanks, these issues 

have to be resolved in order to facilitate 

the widespread use of mid-level ethanol 

blends. 

The Department of Energy and EPA 

are currently working with industry to 

evaluate what changes may be necessary 

to underground storage tank systems, 

fuel dispensers, and refueling vapor 

recovery equipment at fuel retail 

facilities to handle a mid-level ethanol 

blend. If existing equipment proves 

tolerant to a mid-level ethanol blend, 

this could substantially facilitate its 

introduction at retail. If the data 

supports the suitability of legacy retail 

equipment to store/dispense a mid-level 

blend, then the process of seeking 

acceptance by the standard bodies 

discussed above could commence. The 

normal processes used by these 

standards bodies can be lengthy. For 

example, the NFPA has a 3 year cycle 

for evaluating changes to its codes with 

proposals for the current cycle due this 

June. Thus, apart from the need to 

technically evaluate the suitability of 

legacy retail equipment to handle a midlevel ethanol blend, the need to secure 

recognition from standards bodies could 

delay the introduction of a mid-level 

ethanol blend at retail should a waiver 

be granted by EPA. 

If some components of the aboveground existing retail hardware are 

found to be incompatible with a midlevel ethanol blend, it may be possible 

for them to be replaced through normal 

attrition. For example the ‘‘hanging 

hardware’’ which includes the nozzle 

and hose from the dispenser is typically 

replaced every 3 to 5 years. It is also 

possible that only minor changes might 

be needed to equipment that has a 

longer service life which might be 

accomplished without too much 

difficulty/cost. However, if extensive 

new equipment is needed and 

particularly if this involves the breaking 

of concrete, we believe that it is unlikely 

that fuel retailer would opt to install 

equipment specifically for a mid-level 

ethanol blend given the projected future 

need for retail equipment capable of 

handling E85.249

Finally, all vehicles and nonroad 

equipment currently in use are only 

warranted for ethanol levels not 

exceeding E10 (except for FFVs), and 

the owner’s manuals are written to 

reflect this. Before widespread 

acceptance of mid-level ethanol blends 

by consumers can occur, these warranty 

issues would need to be addressed. 

c. Partial Waiver for Mid-Level Blends 

CAA section 211(f)(4), the waiver 

provision, states that the Administrator 

may grant a fuel waiver if a fuel 

manufacturer can demonstrate that the 

fuel ‘‘will not cause or contribute to a 

failure of any emission control device or 

system (over the useful life of the motor 

vehicle, motor vehicle engine, nonroad 

engine or nonroad vehicle in which 

such device or system is used) to 

achieve compliance by the vehicle or 

engine with the emission standards with 

respect to which it has been certified.’’ 

For reasons discussed below, it may be 

possible that these criteria for a midlevel blend waiver may be met for a 

subset of gasoline vehicles or engines 

but not for all gasoline vehicles or 

engines. The waiver criteria are applied 

over the useful life of ‘‘the motor 

vehicle, motor vehicle engine, nonroad 

engine or nonroad vehicle in which 

such device or system is used.’’ 

Assuming the criteria is met for a 

certain subset of vehicles, and that 

adequate measures could be put in place 

to ensure that a waiver fuel were only 

used in that subset of vehicles or 

engines, one interpretation of this 

provision is that the waiver could apply 

only to that subset of vehicles or 

engines. 

One potential outcome from a review 

of the entire body of scientific and 

technical information available may be 

an indication that mid-level ethanol 

blends could meet the criteria of a 

section 211(f)(4) waiver for some 

vehicles and engines but not for others. 

It may be that certain vehicles and 

engines operate as intended using midlevel blends but others may be more 

susceptible to emissions increases or 

durability problems. For example, 

vehicles or engines without newer 

technology that do not readily adjust for 

the higher oxygen level in the fuel may 

experience problems, while newer 

technology vehicles such as those 

meeting our Tier 2 standards may be 

able to adjust for such changes as a 

result of more advanced emissions and 

fuel control equipment. Nonroad 

engines, which are typically small, are 

likely to be most susceptible given the 

less sophisticated technology associated 

with such engines. Given this potential 

outcome, EPA requests comment on all 

aspects, both legal and technical, as to 

the possibility that a section 211(f)(4) 

waiver might be granted, in a partial 

way with conditions, such that the use 

of mid-level blends would be restricted 

to a subset of the gasoline vehicles or 

engines covered by the waiver 

provision, while those nonroad engines 

and vehicles not covered by the waiver 

would continue using fuels with blends 

no greater than E10. 

Any waiver approval, either fully or 

partially, is likely to elicit a market 

response to add E15 blends to E10 and 

E0 blends in the marketplace, rather 

than replace them. Thus consumers 

would merely have an additional choice 

of fuel. 

Experience in past fuel programs has 

shown that even with consumer 

education and fuel implementation 

efforts, there sometimes continues to be 

public concern for new fuel 

requirements. Several examples include 

the phasedown of the amount of lead 

allowed in gasoline in the 1980s and the 

introduction of reformulated gasoline 

(RFG) in 1995. Some segments of the 

public were convinced that the new 

fuels caused vehicle problems or 

decreases in fuel economy. Although 

substantial test data proved otherwise, 

these concerns lingered in some cases 

for several years. As a direct result of 

these experiences, EPA wants to be 

assured that prior to potentially granting 

a waiver for mid-level blends, sufficient 

testing has been conducted to 

demonstrate the compatibility of a 

waiver fuel with engine, fuel and 

emission control system components. 

EPA has previously granted waivers 

with certain restrictions or conditions. 

Among other things, these restrictions 

have included requiring fuels to meet 

certain voluntary consensus-based 

gasoline standards such as those 

developed by the American Society of 

Testing and Materials (ASTM 

standards), requirements that 

precautions be taken to prevent using 

the waiver fuel as a base fuel for adding 

oxygenates, and that certain corrosion 

inhibitors be utilized when producing 

the waived fuel.250 However, in those 

waivers, the conditions placed upon the 

fuel manufacturer were directly related 

to manufacturing the fuel itself. Here, 

the conditions placed upon the fuel 

manufacturer would be on the use of the 

fuel in certain vehicles or engines. In 

other words, the fuel manufacturer 

would have to ensure that the mid-level 

blend was only used in that particular 

subset of vehicles or engines to be able 

to legally manufacture and sell the fuel 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25017 

251Although it is not possible at this time to 

know the contours of a partial waiver with 

conditions, or even if one might be appropriate, the 

remainder of this discussion will refer only to 

vehicles covered by the waiver (and not engines) 

since newer vehicles are more likely to have more 

sophisticated emissions and fuel control 

equipment, while certain engines might be more 

affected for the reasons stated above. 

252See previous discussion in Section V.D.3.b of 

this preamble regarding the issues that would need 

to be addressed to facilitate the introduction of midlevel ethanol blends at retail. 

253According to EIA, gasoline and diesel prices 

were pretty similar on average for a decade from 

1995–2004. However, over the past four years, 

diesel prices have begun to track consistently 

higher than gasoline prices. To date in 2008, diesel 

has been priced more than $0.50/gallon higher than 

gasoline on average. Source: http:// 

tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp. 

under the terms of the waiver. Since it 

would become the fuel manufacturer’s 

responsibility to prevent misfueling, the 

following discussion highlights some of 

the ideas that the fuel manufacturer 

could implement, based on particular 

subsets of vehicles,251 to prevent 

misfueling. 

If a partial waiver covered only newly 

manufactured vehicles, methods 

focused on the manufacturing of the 

vehicle could be utilized to inform the 

buyer that the vehicle was capable of 

operating on the waiver fuel. In this 

case, approaches such as the use of 

vehicle fueling inlet labels and owner’s 

manuals could be utilized in tandem 

with retail station fuel dispenser labels. 

Such an approach depends on the 

attention of the vehicle operator to 

ensure compliance with the waiver. 

Additionally, retail station attendants 

could be trained to provide guidance to 

operators on which vehicles are covered 

under the waiver. 

If only vehicles of certain model years 

were covered, owners would know if 

they could utilize the mid-level blends 

simply by knowing the model year 

(again, in tandem with pump labeling). 

Alternatively, if some portion of the 

existing fleet, not based upon modelyear (such as vehicles meeting EPA Tier 

2 emission standards), would also be 

covered, the approach would have to 

include some means by which the 

operator of such a vehicle would be 

made aware that the vehicle being 

fueled was covered or not covered by 

the waiver. Such an approach would 

likely involve notification of owners of 

covered vehicles, through direct contact 

or education campaigns, and would 

likely require the assistance of the 

vehicle manufacturers. This approach, 

as with other approaches, would require 

pump labeling. 

Other approaches may bring about 

tighter control of misfueling situations 

but may present additional challenges. 

For example, one approach might be to 

provide owners of covered vehicles with 

a transaction card similar to a credit 

card that could be swiped at the 

dispenser to allow for the dispensing of 

a waived mid-level blend. Presumably, 

software and/or hardware at dispensing 

pumps may be able to be adjusted to 

accommodate such an approach. Some 

retail station chains have already 

utilized transponder mechanisms to 

record sales. Similar transponder 

systems could be utilized in place of 

transaction cards. 

The above discussion is not meant to 

be an exhaustive list of possible 

approaches for ensuring compliance 

with a partial waiver, nor does it 

explore all the facets of any single 

approach. EPA recognizes that there 

may be legal and practical limitations 

on what a fuel manufacturer may be 

able to do to ensure compliance with 

the conditions of the partial waiver. 

EPA has not previously imposed this 

type of ‘‘downstream’’ condition on the 

fuel manufacturer as part of a section 

211(f)(4) waiver. EPA does, however, 

have experience with compliance 

problems occurring when two types of 

gasoline have been available at service 

stations. Beginning in the mid-1970s 

with the introduction of unleaded 

gasoline and continuing into the 1980s 

as leaded gasoline was phased out, there 

was significant intentional misfueling 

by consumers. At the time most service 

stations had pumps dispensing both 

leaded and unleaded gasoline and a 

price differential as small as a few cents 

per gallon was enough to cause some 

consumers to misfuel. Higher price 

differentials could occur if, as expected, 

mid-level ethanol blends were to be 

marketed as the regular grade and E0 or 

E10 as the premium grade. The Agency 

seeks comment regarding whether this 

is a reasonable or practical condition for 

this type of waiver. EPA acknowledges 

that the issue of misfueling would be 

challenging in a situation where a 

partial waiver is granted. Therefore, 

EPA solicits comments on what 

measures a fuel manufacturer, EPA or 

others in the gasoline distribution 

network could take for ensuring 

compliance with a partial waiver. 

While EPA has not analyzed the 

specific cost of a conditional waiver, 

such a waiver would likely carry a cost 

similar to the costs described above in 

Section V.D.3.b. Because existing 

equipment in retail stations is certified 

by Underwriters Laboratories only up to 

ten percent ethanol, existing equipment 

would need to be evaluated for its 

acceptability for use with mid-level 

blends (and deemed to be acceptable if 

possible) or it would have to be 

modified/replaced before any ethanol 

blend greater than ten percent could be 

effectuated in the marketplace.252 If 

existing retail equipment is found not to 

be acceptable for storing/dispensing 

mid-level blends, the aforementioned 

infrastructure challenges would be 

present and additional costs would be 

associated with measures adopted for 

the prevention of releases due to 

material incompatibility, as well as 

those associated with misfueling. EPA 

therefore seeks comment on the 

compatibility of the existing retail fuel 

storage/dispensing equipment with midlevel ethanol blends. Further, adoption 

of such a waiver would mean that fewer 

vehicles/engines would be able to 

utilize mid-level blends and, therefore, 

the full impact of mid-level blends on 

the E10 blend wall under such a 

scenario would not be as significant as 

full unrestricted utilization of such 

blends. 

d. Non-Ethanol Cellulosic Biofuel 

Production 

While our analysis describes possible 

pathways by which the market could 

meet the RFS2 requirements with 34 

billion gallons of ethanol as E10 and 

E85, our analysis of the required FFV 

and E85 infrastructure growth as well as 

the required changes to the E10/E85 

price relationship suggests some 

inherent challenges. Furthermore, we 

conclude that the introduction of midlevel ethanol blends (contingent upon 

waiver approval) would by itself not 

allow the country to achieve the RFS2 

standards. Another means of achieving 

the RFS2 volume requirements would 

be through the introduction of nonethanol cellulosic biofuels. The growing 

spread in gasoline and diesel pricing 

implies that we are currently moving in 

the direction of being oversupplied with 

gasoline and undersupplied with 

diesel.253 As such, it makes sense that 

the market might preferentially 

investigate diesel fuel replacements, 

e.g., cellulosic diesel via FischerTropsch synthesis, pyrolysis, or 

catalytic depolymerization. These fuels 

would meet the definition of cellulosic 

biofuel (as well as advanced biofuel) 

under the proposed RFS2 program and 

help reduce the ethanol blend wall 

impacts associated with this rule. 

Although for our analysis we assumed 

that the cellulosic biofuel standard 

would be met with ethanol, the market 

could choose a significant volume of 

other non-ethanol renewable fuels. DOE 

and other agencies are currently 

providing grants to support critical 

25018 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

254Memorandum from Mary T. Smith, Director of 

the Field Operations and Support Division, to State/ 

Local Oxygenated Fuels Contacts, October 5, 1992. 

Subject: ‘‘Testing Tolerance’’. 

research into these second-generation 

cellulosic feedstock conversion 

technologies. DOE is also providing loan 

guarantees to help with the 

commercialization of such technologies. 

For more information on non-ethanol 

cellulosic biofuels, refer to Section V.A. 

or Section 1.4.3 of the DRIA. 

e. Measurement Tolerance For E10 

Some stakeholders have suggested 

that the implementation of a tolerance 

in the measurement of the ethanol 

content of gasoline could allow more 

ethanol to be used in existing vehicles 

without the need for a formal waiver 

and without the need for more FFVs. 

Such a tolerance could allow ethanol 

contents slightly higher than 10 volume 

percent while still treating such blends 

as meeting the 10 volume percent 

limitation on the ethanol content of 

gasoline. 

Although there is no explicit written 

precedent for permitting ethanol 

contents higher than 10 vol%, some 

have speculated that current vehicles 

would not exhibit any noticeable change 

in performance, durability, or emissions 

if a small measurement tolerance for 

ethanol content of gasoline were 

allowed. The current specified test 

method for oxygen content ASTM D– 

5599–00 includes estimates of the 

measurement reproducibility that could 

be used to inform the determination of 

an appropriate tolerance for ethanol 

content in gasoline. For instance, based 

on the provided reproducibility, a 

measurement as high as 11 vol% 

ethanol in gasoline might be possible for 

gasoline that was blended to meet a 10 

vol% ethanol requirement. Historically, 

however, EPA has always enforced the 

10 vol% waiver at the 10 vol% level 

without any tolerance. 

The 1978 gasohol waiver application 

requested a blend of 90% unleaded 

gasoline and 10% anhydrous ethanol. 

Although not specified in the 

application, the convention and the 

practical approach for blending ethanol 

into gasoline in 1978 was by volume, 

and it has continued to be by volume. 

Thus, the limit on ethanol in gasoline 

under the waiver is 10% by volume. 

This is approximately 3.5% oxygen by 

weight. The waiver request did not 

apply to a level of ethanol in gasoline 

beyond 10%, and since the application 

was approved by default after 180 days 

due to the fact that the Administrator 

did not make an explicit decision in this 

timeframe, there is no formal approval 

that could have indicated what 

measurement tolerances might have 

been acceptable. Thus it has historically 

been enforced at the 10 vol% limit 

without any enforcement tolerance. 

However, parties who have raised this 

option have suggested that the Agency’s 

previous treatment of the oxygenate 

content of gasoline may provide a 

precedent that would allow for a higher 

measurement tolerance for ethanol 

content. 

Prior to and after 1981, several 

waivers issued by the Agency allowed 

the use of various alcohols and ethers in 

unleaded gasoline. In 1981, the 

‘‘substantially similar’’ interpretive rule 

for unleaded gasoline allowed certain 

alcohols and ethers at up to 2.0% 

oxygen by weight. In 1991 the limit was 

increased to 2.7% oxygen by weight. For 

each of these waivers, the unleaded 

gasoline base to which the oxygenate 

was to be added was to be initially free 

of oxygenate. With the exception of 

ethanol, oxygenates, mostly MTBE, were 

blended at the refinery, with the refiner 

in control of the gasoline used for 

blending. This enabled the refiner to 

ensure that it was free of oxygenate 

prior to blending. Ethanol was primarily 

blended at terminals. In order to ensure 

that gasoline blended with ethanol at 

the terminal was free of other 

oxygenates, the ethanol blender first had 

to check for the presence of other 

oxygenates in the base gasoline. In the 

mid-1980’s ethanol blenders informed 

EPA that they were having difficulty 

finding oxygenate-free gasoline. Much 

of gasoline had at least trace amounts of 

MTBE due to commingling of gasolines 

with different oxygenates in the fungible 

pipeline system. In order to continue to 

allow the blending of ethanol up to the 

10 vol% limit, EPA issued a letter 

stating that it would not consider it to 

be a violation of the ethanol sub-sim 

waiver if up to 10% by volume ethanol 

were added to unleaded gasoline 

containing no more than 2% by volume 

MTBE. However, the MTBE must have 

been present only as a result of 

commingling during storage or transport 

and not purposefully added as an 

additional component to the ethanol 

blend. 

Subsequently, two other statements 

by EPA provided guidance on the 

allowable oxygen content of oxygenated 

fuels. For instance, in a memorandum 

dated October 5, 1992, EPA provided 

interim guidance for states that allowed 

averaging programs.254 This guidance 

allowed the oxygen content of ethanol 

to be as high as 3.8% by weight, but did 

not indicate that the ethanol 

concentration could be higher than 10 

vol%. Also, in a 1995 RFG/Antidumping Q&A it was noted that the 

maximum oxygen range for the simple 

and complex models was 4.0% by 

weight. This range was implemented to 

once again continue to allow the 

blending of ethanol up to the 10 vol% 

limit in cases where an extremely low 

gasoline density might increase the 

calculated weight percent oxygen 

content for E10 above the more typical 

3.5–3.7 wt% range. 

Although we acknowledge that the 

currently specified test method ASTM 

D–5599–00 includes some variability, 

ethanol is different than many other fuel 

properties and components that are 

controlled in other fuel programs in one 

important respect. Fuel properties such 

as RVP, and components such as sulfur 

and benzene, are natural characteristics 

of gasoline as a result of the chemical 

nature of crude oil and the refining 

process. Their level or concentration in 

gasoline is unknown until measured, 

and then is dependent upon accuracy of 

the test method. In contrast, ethanol is 

intentionally added in known amounts 

using equipment designed to ensure a 

specific concentration within a small 

fraction of one percent. Parties that 

blend ethanol into gasoline therefore 

have precise control over the final 

concentration. Thus, a measurement 

tolerance for ethanol would be less 

appropriate than measurement 

tolerances for other fuel properties and 

components. 

We request comment on whether a 

measurement tolerance should be 

allowed for the ethanol content of 

gasoline, the basis for such a tolerance, 

and what tolerance if any would be 

appropriate. We also request comment 

on whether such a tolerance would fit 

within the existing Underwriters 

Laboratories, Inc. (UL) approval for the 

safety of equipment at refueling stations, 

including underground storage tanks, 

pumps, piping, seals, etc. 

f. Redefining ‘‘Substantially Similar’’ to 

Allow Mid-Level Ethanol Blends 

Section 211(f)(1) prohibits the 

introduction into commerce, or increase 

in the concentration in use of, gasoline 

or gasoline additives for use in motor 

vehicles unless they are substantially 

similar to the gasoline or gasoline 

additives used in the certification of 

new motor vehicles or motor vehicle 

engines. EPA may grant a waiver of this 

prohibition under section 211(f)(4) of 

the Clean Air Act provided that the fuel 

or fuel additive ‘‘will not cause or 

contribute to a failure of any emission 

control device or system (over the useful 

life of the motor vehicle, motor vehicle 

engine, nonroad engine or nonroad 

vehicle in which the device or system 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25019 

255 43 FR 11258 (March 17, 1978), 43 FR 24131 

(June 2, 1978). 

256 45 FR 67443 (October 10, 1980), 46 FR 38582 

(July 28, 1981). 

257 56 FR 5352 (February 11, 1991). 

258 56 FR at 5353. 

259 73 FR 22277 (April 25, 2008). 

260One point to be clear on is that the 

substantially similar provision relates to fuels used 

in certification. It is not an issue of whether midlevel blends are substantially similar to a fuel that 

has received a waiver of this prohibition. See 46 FR 

38582, 38583 (July 28, 1981). The fuels used in 

certification include the test fuels used for exhaust 

testing, test fuels for evaporative emissions testing, 

and the fuels used in the durability process. 

261 It has also been suggested that nonroad 

engines and equipment may experience greater 

emissions effects and durability problems when 

using mid-level blends. 

262As mentioned earlier, EPA has typically used 

the oxygen weight percent convention when 

interpreting the ‘‘substantially similar’’ provision. A 

change in the ‘‘substantially similar’’ interpretation 

to allow for up to 4.5% oxygen by weight in the 

form of ethanol would essentially accommodate 

ethanol blends up to 12% by volume since the vast 

majority of gasolines blended at 12% by volume 

ethanol would not exceed this oxygen weight 

percent limit. 

is used) to achieve compliance by the 

vehicle or engine with the emission 

standards to which it has been 

certified.’’ 

EPA first interpreted the term 

‘‘substantially similar’’ for unleaded 

gasoline and its additives in 1978.255

Recognizing that this interpretation was 

too limited, EPA updated it in 1980, and 

again in 1981.256 EPA set the limits 

contained in the interpretation based on 

the physical and chemical similarities of 

the fuel or fuel additives to those used 

in the motor vehicle certification 

process. EPA also considered 

information available regarding the 

emission effects that such fuels and 

additives would exhibit relative to the 

emissions performance of the 

certification fuels and fuel additives. 

The 1981 interpretative rule identified 

the characteristics and specifications 

that EPA determined would make a fuel 

or fuel additive ‘‘substantially similar’’ 

to those used in certification. Under this 

rule, a fuel or fuel additive would be 

considered substantially similar if it 

satisfied certain limits on fuel and fuel 

additive composition, did not exceed a 

maximum allowable oxygen content of 

fuel at 2.0% by weight, and met certain 

ASTM specifications. Comments on this 

interpretative rule requested that EPA 

increase the maximum oxygen 

concentration up to 3.5% oxygen by 

weight, but EPA rejected this 

recommendation, stating that it would 

keep the limit at 2.0% because of 

concerns over emissions, material 

compatibility, and drivability from use 

of various alcohols at higher oxygen 

contents. 

In 1991, EPA amended the 

interpretive rule by revising the oxygen 

content criteria to allow fuels containing 

aliphatic ethers and/or alcohols 

(excluding methanol) to contain up to 

2.7% by weight oxygen.257 EPA based 

this increase in the oxygen content on 

its review of information on a wide 

variety of alcohol and ether blends, 

leading it to determine that ‘‘unleaded 

gasolines with such oxygen content are 

chemically and physically substantially 

similar to, and have been shown to have 

emissions properties substantially 

similar to, unleaded gasolines used in 

light-duty vehicle certification.’’ 258

Finally, in 2008, EPA amended the 

interpretive rule to allow flexibility for 

the vapor/liquid ratio specification for 

fuel introduced into commerce in the 

state of Alaska to improve cold starting 

for vehicles during the winter months in 

Alaska.259 Thus the ‘‘substantially 

similar’’ interpretive rule for unleaded 

gasoline presently allows oxygen 

content up to 2.7% by weight for certain 

ethers and alcohols. 

A waiver of the substantially similar 

prohibition was provided by operation 

of law in 1979 under CAA section 

211(f)(4), allowing a gasoline-alcohol 

fuel blend with up to 10% ethanol by 

volume (E10) (‘‘E10 Waiver’’). E10 has 

an oxygen content which typically 

ranges between 3.5 and 3.7% by weight, 

depending on the specific gravity of the 

gasoline. Any ethanol blends with 

greater than 10% ethanol by volume 

would have an oxygen content which 

exceeds the 2.7% by weight allowed 

under the current interpretation of 

‘‘substantially similar.’’ Therefore, 

under the 1991 interpretive rule, midlevel ethanol blends would not be 

considered substantially similar and 

would require a CAA section 211(f)(4) 

waiver. 

It has been suggested to EPA that we 

should update the interpretive rule such 

that mid-level ethanol blends would be 

considered substantially similar. As in 

the past, this would involve 

consideration of the physical and 

chemical similarities of such mid-level 

blends to fuels used in the certification 

process, as well as information about 

the expected emissions effects of such 

mid-level blends.260 EPA invites 

comment on whether mid-level blends 

of ethanol are physically and chemically 

similar enough to the fuels used in the 

motor vehicle certification process such 

that they could be considered 

‘‘substantially similar’’ to the 

certification fuels used by EPA. With 

respect to the emissions effects of midlevel blends on emissions performance, 

EPA recognizes that there may be 

different impacts depending on the kind 

of motor vehicle involved. For example, 

it has been suggested that older 

technology motor vehicles and engines 

may have emissions and durability 

impacts from ethanol blends higher than 

10 percent, while Tier 2 and later 

technology vehicles—2004 and later 

model year vehicles—may have fewer 

such impacts.261 These more recent 

technology vehicles represent an ever 

growing proportion of the in-use fleet. 

DOE is currently conducting various test 

programs to ascertain the impacts of 

higher level ethanol blends on vehicles 

and equipment. 

EPA seeks comment on all of the 

issues involved with reconsidering its 

interpretation of the term ‘‘substantially 

similar’’ to include gasoline blended 

with ethanol to contain up to 4.5% 

oxygen by weight. If EPA revised the 

substantially similar interpretation in 

this manner, gasoline blended with up 

to 12% ethanol by volume (E12) would 

be considered ‘‘substantially 

similar.’’ 262 Given the possibility, based 

upon engineering judgment, of a varying 

impact of a mid-level ethanol blends on 

different technology vehicles, EPA 

invites comment on limiting such an 

interpretation to gasoline intended for 

use in Tier 2 and later motor vehicles. 

We estimate that defining E12 as 

‘‘substantially similar’’ for Tier 2 and 

later motor vehicles could delay the 

saturation of the gasoline market with 

ethanol for up to a year, allowing for 

more comprehensive testing on higher 

blend levels to be carried out. However, 

before EPA could determine whether it 

was appropriate to revise the 

interpretation of ‘‘substantially similar’’ 

for gasoline to include gasoline-alcohol 

fuels blended with up to 12% ethanol, 

information would need to be provided 

to EPA that would allow for a robust 

assessment of the impact of E12 over the 

full useful life of Tier 2 and later motor 

vehicles addressing emissions (both 

tailpipe and evaporative emissions), 

materials compatibility, and drivability. 

Furthermore, E12 would still need to 

fulfill registration requirements (i.e. 

speciation and health effects testing 

found at 40 CFR 79.52 and 40 CFR 

79.53). 

EPA also seeks comments on 

additional regulatory and 

implementation issues that would arise 

as a result of changing the ‘‘substantially 

similar’’ definition to allow for E12. 

These issues as identified for mid-level 

blends in the discussion in Section 

V.D.3.b include, but are not necessarily 

limited to, the applicability of the 1.0 

psi RVP waiver with regard to 10% 

ethanol blends found at 40 CFR 

25020 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

263 In this preamble, we are considering ‘‘lifecycle 

analysis’’ in the context of estimating GHG 

emissions, as required by EISA. More generally, the 

term ‘‘lifecycle analysis’’ or ‘‘assessment’’ has been 

defined as an evaluation of all the environmental 

impacts across the range of media/exposure 

pathways that are associated with a ‘‘cradle to 

grave’’ view of a product or set of policies. For more 

information on this broader context, please see the 

2006 EPA publication ‘‘Life Cycle Assessment: 

Principles and Practice (EPA/600/R–06/060). 

80.27(d), Clean Air Act section 211(h); 

the accommodation of ethanol blends in 

making calculations utilizing the 

complex model for reformulated and 

conventional gasoline at 40 CFR 80.45; 

and detergent certification requirements 

found at 40 CFR 80 (Subpart G). 

Emissions speciation and health effects 

testing is required for oxygenate-specific 

blends under 40 CFR 79 (Subpart F). 

Such testing is currently underway for 

10% ethanol blends but not for ethanol 

levels higher than 10 percent. 

Additionally, if E12 was allowed under 

the ‘‘substantially similar’’ definition, 

presumably such a blend would have to 

meet one of the volatility classes of 

ASTM D4814–88, which is not now the 

case with some blends of 10% ethanol 

blended under the E10 Waiver. Any 

change in the allowable maximum 

ethanol level in motor fuels will impact 

these and, potentially, other motor fuel 

regulations. 

Furthermore, there are also 

implications beyond EPA’s motor fuel 

regulations. Existing equipment in retail 

stations is certified by Underwriters 

Laboratories only up to 10% ethanol. 

Thus, either existing equipment would 

need to be recertified for E12 (if 

possible) or it would have to be replaced 

before E12 could be effectuated in the 

marketplace. In addition, the 

substantially similar prohibition applies 

to the fuel manufacturer, and if the 

reinterpretation only applied to gasoline 

used with Tier 2 and later motor 

vehicles, then the manufacturer of a 

mid-level blend could not introduce it 

into commerce for use with any other 

motor vehicles. This means that the fuel 

distribution system would need to be 

structured in such a way that the fuel 

manufacturer could appropriately 

ensure that the fuel was only used in 

Tier 2 or later motor vehicles. 

Preventing the misfueling of mid-level 

blends into vehicles and engines not 

specified in the interpretive rule, and 

ensuring the availability of fuels for 

other vehicles and engines, poses a 

major problem with reinterpreting 

‘‘substantially similar’’ to include midlevel blends with a restriction for use in 

Tier 2 and later motor vehicles. (For a 

more detailed discussion on this issue, 

see Section V.D.3.c above). We seek 

comment on these logistical and 

regulatory concerns as well. 

VI. Impacts of the Program on 

Greenhouse Gas Emissions 

A. Introduction 

Lifecycle modeling, often referred to 

as fuel cycle or well-to-wheel analysis, 

assesses the net impacts of a fuel 

throughout each stage of its production 

and use including production/extraction 

of the feedstock, feedstock 

transportation, fuel production, fuel 

transportation and distribution, and 

tailpipe emissions.263 This section 

describes and seeks comment on the 

methodology developed by EPA to 

determine the lifecycle greenhouse gas 

(GHG) emissions of biofuels fuels as 

required by EISA as well as the 

petroleum-based transportation fuels 

being replaced. While much of the 

discussion below focuses on those 

portions of lifecycle assessment 

particularly important to biofuel 

production, the basic methodology was 

the same for analyzing both petroleumbased fuels and biofuels. This 

methodology was utilized to determine 

which biofuels (both domestic and 

imported) qualify for the four different 

GHG reduction thresholds established 

in EISA. This threshold assessment 

compares the lifecycle emissions of a 

particular biofuel including its 

production pathway against the 

lifecycle emissions of the petroleumbased fuel it is replacing (e.g., ethanol 

replacing gasoline or biodiesel replacing 

diesel). This section also seeks comment 

on the Agency’s proposal to utilize the 

discretion provided in EISA to adjust 

these thresholds downward should 

certain conditions be met. We also 

explain how feedstocks and fuel types 

not included in our analysis will be 

addressed and incorporated in the 

future. The overall GHG benefits of the 

RFS program, which are based on the 

same methodology presented here, are 

provided in Section VI.F. 

As described in detail below, EPA has 

analyzed the lifecycle GHG impacts of 

the range of biofuels currently expected 

to contribute significantly to meeting 

the volume mandates of EISA through 

2022. In these analyses we have used 

the best science available. Our analysis 

relies on peer reviewed models and the 

best estimate of important trends in 

agricultural practices and fuel 

production technologies as these may 

impact our prediction of individual 

biofuel GHG performance through 2022. 

We have identified and highlighted 

assumptions and model inputs that 

particularly influence our assessment 

and seek comment on these 

assumptions, the models we have used 

and our overall methodology so as to 

assure the most robust assessment of 

lifecycle GHG performance for the final 

rule. 

EPA believes that compliance with 

the EISA mandate—determining the 

aggregate GHG emissions related to the 

full fuel lifecycle, including both direct 

emissions and significant indirect 

emissions such as land use changes— 

makes it necessary to assess those direct 

and indirect impacts that occur not just 

within the United States and also those 

that occur in other countries. This 

applies to determining the lifecycle 

emissions for petroleum-based fuels, to 

determine the baseline, as well as the 

lifecycle emissions for biofuels. For 

biofuels, this includes evaluating 

significant emissions from indirect land 

use changes that occur in other 

countries as a result of the increased 

production and importation of biofuels 

in the U.S. As detailed below, we have 

included the GHG emission impacts of 

international indirect land use changes. 

We recognize the significance of 

including international land use 

emissions impact and in our analysis 

presentation we have been transparent 

in breaking out the various sources of 

GHG emissions so that the reader can 

readily see the impact of including 

international land use impacts. 

In addition to the many technical 

issues addressed in this proposal, this 

section also discusses the emissions 

decreases and increases associated with 

the different parts of the lifecycle 

emissions of various biofuels, and the 

timeframes in which these emissions 

changes occur. Determining a single 

lifecycle value that best represents this 

combination of emissions increases and 

decreases occurring over time led EPA 

to consider various alternative ways to 

analyze the timeframe of emissions 

related to biofuel production and use as 

well as options for adjusting or 

discounting these emissions to 

determine their net present value. 

Several variations of time period and 

discount rate are discussed. The 

analytical time horizon and the choice 

whether to discount GHG emissions 

and, if so, at what appropriate rate can 

have a significant impact on the final 

assessment of the lifecycle GHG 

emissions impacts of individual biofuels 

as well as the overall GHG impacts of 

these EISA provisions and this rule. 

We believe that our lifecycle analysis 

is based on the best available science, 

and recognize that in some aspects it 

represents a cutting edge approach to 

addressing lifecycle GHG emissions. 

Because of this, varying degrees of 

uncertainty are in our analysis. For this 

proposal, we conducted a number of 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25021 

264Clean Air Act Section 211(o)(1). 

265See also, Conceptual and Methodological 

Issues in Lifecycle Analysis of Transportation 

Fuels, Mark A. Delucchi, Institute of Transportation 

Studies, University of California, Davis, 2004, UCD– 

ITS–RR–04–45 for a description of issues with 

traditional lifecycle analysis used to model GHG 

impacts of biofuels and biofuel policies. 

266Fargione, J., J. Hill, D. Tilman, S. Polasky, and 

P. Hawthorne. 2008. Land clearing and the biofuel 

carbon debt. Science 319:1235–1238. See http:// 

www.sciencemag.org/cgi/reprint/319/5867/ 

1235.pdf. 

267Searchinger, T., R. Heimlich, R.A. Houghton, 

F. Dong, A. Elobeid, J. Fabiosa, S. Tokgoz, D. Hayes, 

and T.-H. Yu. 2008. Use of U.S. croplands for 

biofuels increases greenhouse gases through 

emissions from land-use change. Science 319:1238– 

1240. See http://www.sciencemag.org/cgi/reprint/ 

319/5867/1238.pdf. 

sensitivity analyses which focus on key 

parameters and demonstrate how our 

assessments might change under 

alternative assumptions. By focusing 

attention on these key parameters, the 

comments we receive as well as 

additional investigation and analysis by 

EPA will allow narrowing of uncertainty 

concerns for the final rule. In addition 

to this sensitivity analysis approach, we 

will also explore options for more 

formal uncertainty analyses for the final 

rule to the extent possible. 

Because lifecycle analysis is a new 

part of the RFS program, in addition to 

the formal comment period on the 

proposed rule, EPA is making multiple 

efforts to solicit public and expert 

feedback on our proposed approach. As 

discussed in Section XI, EPA plans to 

hold a public workshop during the 

comment period focused specifically on 

our lifecycle analysis to help ensure full 

understanding of the analyses 

conducted, the issues addressed and 

options that should be considered. We 

expect that this workshop will help 

ensure that we receive the most 

thoughtful and useful comments to this 

proposal and that the best methodology 

and assumptions are used for 

calculating GHG emissions impacts of 

fuels for the final rule. Additionally we 

will conduct peer-reviews of key 

components of our analysis. As 

explained in more detail in the 

following sections, EPA is specifically 

seeking peer review of: Our use of 

satellite data to project future land use 

changes; the land conversion GHG 

emissions factors estimated by Winrock; 

our estimates of GHG emissions from 

foreign crop production; methods to 

account for the variable timing of GHG 

emissions; and how models are used 

together to provide overall lifecycle 

GHG estimates. 

The regulatory purpose of the 

lifecycle greenhouse gas emissions 

analysis is to determine whether 

renewable fuels meet the GHG 

thresholds for the different categories of 

renewable fuel. 

1. Definition of Lifecycle GHG 

Emissions 

The GHG provisions in EISA are 

notable for the GHG thresholds 

mandated for each category of 

renewable fuel and also the mandated 

lifecycle approach to those thresholds. 

Renewable fuel must, unless 

‘‘grandfathered’’ as discussed in Section 

II.B.3., achieve at least 20% reduction in 

lifecycle greenhouse gas emissions 

compared to the average lifecycle 

greenhouse gas emissions for gasoline or 

diesel sold or distributed as 

transportation fuel in 2005. Similarly, 

biomass-based diesel and advanced 

biofuels must achieve a 50% reduction, 

and cellulosic biofuels a 60% reduction, 

unless these thresholds are adjusted 

according to the provisions in EISA. To 

EPA’s knowledge, the GHG reduction 

thresholds presented in EISA are the 

first lifecycle GHG performance 

requirements included in federal law. 

These thresholds, in combination with 

the renewable fuel volume mandates, 

are designed to ensure significant GHG 

emission reductions from the use of 

renewable fuels and encourage the use 

of GHG-reducing renewable fuels. 

The definition of lifecycle greenhouse 

gas emissions established by Congress is 

also critical. Congress specified that: 

The term ‘lifecycle greenhouse gas 

emissions’ means the aggregate quantity of 

greenhouse gas emissions (including direct 

emissions and significant indirect emissions 

such as significant emissions from land use 

changes), as determined by the 

Administrator, related to the full fuel 

lifecycle, including all stages of fuel and 

feedstock production and distribution, from 

feedstock generation or extraction through 

the distribution and delivery and use of the 

finished fuel to the ultimate consumer, where 

the mass values for all greenhouse gases are 

adjusted to account for their relative global 

warming potential.264

This definition requires EPA to look 

broadly at lifecycle analyses and to 

develop a methodology that accounts for 

all the important factors that may 

significantly influence this assessment, 

including the secondary or indirect 

impacts of expanded biofuels use. EPA’s 

analysis described below indicates that 

the assessment of lifecycle GHG 

emissions for biofuels is significantly 

affected by the secondary agricultural 

sector GHG impacts from increased 

biofuel feedstock production (e.g., 

changes in livestock emissions due to 

changes in agricultural commodity 

prices) and also by the international 

impact of land use change from 

increased biofuel feedstock production. 

Thus, these factors must be 

appropriately incorporated into EPA’s 

lifecycle methodology to properly assess 

full lifecycle GHG performance of 

biofuels in accordance with the EISA 

definition. 

2. History and Evolution of GHG 

Lifecycle Analysis 

Traditionally, the GHG lifecycle 

analysis of fuels has involved 

calculating the emissions associated 

with each individual stage in the 

production and use of the fuel (e.g., 

growing or extracting the feedstock, 

moving the feedstock to the processing 

plant, processing the feedstock into fuel, 

moving the fuel to market, and 

combusting the fuel.) EPA used this 

approach for the lifecycle modeling 

conducted for the RFS1 program in 

2005. However, it has become 

increasingly apparent that this type of 

first order or attributional lifecycle 

modeling has notable shortcomings, 

especially when evaluating the 

implications of biofuel policies.265 In 

fact, the main criticism EPA received in 

reaction to our previous RFS1 lifecycle 

analysis was that we did not include 

important secondary, indirect, or 

consequential impacts of biofuel 

production and use. 

Several studies and analyses 

conducted since the completion of RFS1 

have contributed to our understanding 

of the lifecycle GHG emissions of 

biofuel production. These studies, and 

others, have highlighted the potential 

impacts of biofuel production on the 

agricultural sector and have specifically 

identified land use change impacts as an 

important consideration when 

determining GHG impacts of 

biofuels.266 267 In the meantime, the 

dramatic increase in U.S. production of 

biofuels has heightened the concern 

about the impacts biofuels might have 

on land use and has increased the 

importance of considering these indirect 

impacts in lifecycle analysis. 

Based on the evolution of lifecycle 

analysis and the new requirements of 

EISA, we have developed a 

comprehensive methodology for 

estimating the lifecycle GHG emissions 

associated with renewable fuels. 

Through dozens of meetings with a 

wide range of experts and stakeholders, 

EPA has shared and sought input on 

this methodology. We also have relied 

on the expertise of the U.S. Department 

of Agriculture (USDA) and the 

Department of Energy (DOE) to help 

inform many of the key assumptions 

and modeling inputs for this analysis. 

Dialogue with the State of California 

and the European Union on their 

parallel, on-going efforts in GHG 

25022 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

268We then normalize those impacts for each 

gallon of fuel (or Btu) by dividing total impacts over 

the given volume change. 

lifecycle analysis has also helped inform 

EPA’s methodology. As part of this 

discussion, we have identified several of 

the key drivers associated with these 

lifecycle GHG emissions estimates, 

including assumptions about 

international land use change and the 

timing of GHG emissions over time. The 

inputs we have received through these 

interactions are reflected throughout 

this section. 

Specifically EPA has worked closely 

with the California Air Resources Board 

(CARB) regarding their development of 

transportation fuels lifecycle GHG 

impacts. California Executive Order S– 

1–07, the Low Carbon Fuel Standard 

(LCFS) (issued on January 18, 2007), 

calls for a reduction of at least 10 

percent in the carbon intensity of 

California’s transportation fuels by 

2020. CARB has worked to develop 

lifecycle GHG impacts of different fuels 

for this Executive Order rulemaking. 

More information about this rulemaking 

and the lifecycle analysis conducted by 

California can be found at http:// 

www.arb.ca.gov/fuels/lcfs/lcfs.htm. EPA 

will continue to coordinate with 

California on this rulemaking and the 

biofuels lifecycle GHG analysis work. 

Because this lifecycle GHG emissions 

analysis is complex and requires the use 

of sophisticated computer models, we 

have taken several steps to increase the 

transparency associated with our 

analysis. For example, we have updated 

the model documentation for the Forest 

and Agricultural Sector Optimization 

Model (FASOM), which is included in 

the docket. In addition, we have 

highlighted key assumptions in FASOM 

and the Food and Agricultural Policy 

Research Institute (FAPRI) models that 

impact the results of our analysis. 

Finally, this NPRM provides an 

important opportunity for the Agency to 

present our work and to receive input 

from stakeholders and experts in this 

field. We will also continue to refine our 

analysis between the proposed and final 

rules, and we will add or update 

information to the docket as it becomes 

available. 

B. Methodology 

This section describes EPA’s 

methodology for assessing the lifecycle 

GHG emissions associated with each 

biofuel evaluated as well as the 

petroleum-based gasoline and diesel 

fuel these biofuels would replace. 

Whereas lifecycle GHG emission 

methodologies have been well studied 

and established for petroleum-based 

gasoline and diesel fuel, much of EPA’s 

work has focused on newly developing 

lifecycle methodologies for biofuels. 

Therefore, much of the following 

section describes the biofuels-related 

methodologies and identifies important 

issues for comment. Assessing the 

complete lifecycle GHG impact for each 

individual biofuel mandated by EISA 

requires that a number of key 

methodological issues be addressed— 

from the choice of a baseline to the 

selection of the most credible technique 

for predicting international land use 

conversion due to the increase in U.S. 

renewable fuels demand, to accounting 

for the time dimension of changes in 

GHG emissions. In this section, we first 

describe the scenarios we have analyzed 

for this proposal. Second, we discuss 

the scope of our analysis and what is 

included in our estimates. Third, we 

provide details on the tools and models 

we used to quantify the GHG emissions 

associated with the different fuels. 

Fourth, we discuss the uncertainties 

associated with lifecycle analysis and 

how we have addressed them. Fifth, we 

describe the different components of the 

lifecycle that we have analyzed and the 

key questions we have addressed in this 

analysis. 

1. Scenario Description 

To quantify the lifecycle GHG 

emissions associated with the increase 

in renewable fuel mandated by EISA, 

we compared the differences in total 

GHG emissions between two future 

scenarios. The first assumed a ‘‘business 

as usual’’ volume of a particular 

renewable fuel based on what would 

likely be in the fuel pool in 2022 

without EISA, as predicted by the 

Energy Information Agency’s Annual 

Energy Outlook (AEO) for 2007 (which 

took into account the economic and 

policy factors in existence in 2007 

before EISA). The second assumed the 

higher volume of renewable fuels as 

mandated by EISA for 2022. For each 

individual biofuel, we analyzed the 

incremental GHG emission impacts of 

increasing the volume of that fuel to the 

total mix of biofuels needed to meet the 

EISA requirements. Rather than focus 

on the impacts associated with a 

specific gallon of fuel and tracking 

inputs and outputs across different 

lifecycle stages, we determined the 

overall aggregate impacts across sections 

of the economy in response to a given 

volume change in the amount of biofuel 

produced.268

This analysis is not a comparison of 

biofuel produced today versus biofuel 

produced in the future. Instead, it is a 

comparison of two future scenarios. Any 

projected changes in factors such as 

crop yields, energy costs, or production 

plant efficiencies, both domestically and 

internationally, are reflected in both 

scenarios. We focused our analyses on 

2022 results for three reasons. First, it 

would require an extremely complex 

assessment and administratively 

difficult implementation program to 

track how biofuel production might 

continuously change from month to 

month or year to year. Instead, it seems 

appropriate that each biofuel be 

assessed a level of GHG performance 

that is constant over the implementation 

of this rule, allowing fuel providers to 

anticipate how these GHG performance 

assessments should affect their 

production plans. Second, it is 

appropriate to focus on 2022, the final 

year of ramp up in the required volumes 

of renewable fuel as this year. 

Assessment in this year allows the 

complete fuel volumes specified in 

EISA to be incorporated. Third, since 

the GHG assessment compares 

performance between a business as 

usual case and the mandated volumes 

case, many of the factors that change 

over time such as crop yield per acre are 

reflected in both cases. Therefore the 

differences in these parallel assessments 

are unlikely to vary significantly over 

time. 

EPA requests comment on its 

proposal to adopt fixed assessments of 

fuels meeting the GHG thresholds based 

on a 2022 performance assessment. 

Additional information on the scenarios 

modeled and the supplemental analyses 

that will be conducted for the final rule 

is included in Chapter 2 of the DRIA. 

In the existing Renewable Fuel 

Standard rules adopted in response to 

the Energy Policy Act of 2005, biofuels 

and RINs associated with them are not 

based on regional differences of where 

the feedstock was grown or the biofuel 

was produced. In effect, the RINs apply 

to a national average of the fuel type. 

Similarly, this proposal does not 

distinguish biofuel on the basis of where 

within the country the biofuel feedstock 

was grown or the biofuel produced. 

Thus, for example, ethanol produced 

from corn starch using the same 

production technology will receive the 

same GHG lifecycle assessment 

regardless of where the corn was grown 

or at what facility the biofuel was 

produced. There are regional differences 

in soil types, weather conditions, and 

other factors which could affect, for 

example, the amount of fertilizer 

applied and thus the GHG impact of 

corn production. Such factors could 

vary somewhat across a region, within 

a state and even within a county. The 

agricultural models used to conduct this 

analysis do distinguish crop production 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25023 

269Arguably shifts in acreage between different 

crops also could be considered a land use change, 

but we believe there will be less confusion if the 

term land use change is used with respect to 

changes in land such as changing from savannah or 

forest to cropland. There is no difference in result, 

as in both cases the emissions need to be 

significant. 

by region domestically and by country 

internationally. However, biofuel 

feedstocks such as corn or soybean oil 

are well traded commodities including 

internationally. So, for example, if corn 

in a certain location in Iowa is used to 

produce ethanol, corn from all other 

regions will be used to replace that corn 

for all its other potential uses. 

Therefore, it is not appropriate to 

ascribe the indirect affects, both 

domestically and internationally, to 

corn grown in one area differently to 

corn (or other biofuel feedstock) grown 

in another area. Our national treatment 

of biofuel feedstock also pertains to 

fuels produced in other countries. Thus 

for example, sugarcane-based ethanol 

produced in Brazil is all treated the 

same regardless of where the sugarcane 

was grown in Brazil. Nevertheless, 

comments are invited on the option of 

differentiating biofuels in the future 

based on the location of their feedstock 

production within a country. 

2. Scope of the Analysis 

a. Legal Interpretation of Lifecycle 

Greenhouse Gas Emissions 

As described in VI.A.1, the definition 

of lifecycle greenhouse gas emissions 

refers to the ‘‘aggregate quantity of GHG 

emissions’’ that are ‘‘related to the full 

fuel lifecycle.’’ The fuel lifecycle 

includes ‘‘all stages of fuel and 

feedstock production and distribution, 

from feedstock generation or extraction 

through * * * use of the finished fuel 

to the ultimate consumer.’’ The 

aggregate quantity of GHG emissions 

includes ‘‘direct emissions’’ and 

‘‘significant indirect emissions such as 

significant emission from land use 

changes.’’ This provision is written in 

generally broad and expansive terms, 

such as ‘‘aggregate quantity’’, ‘‘related 

to’’, ‘‘full fuel lifecycle’’, and ‘‘all 

stages’’ of production and distribution. 

At the same time, these and other terms 

are not themselves defined and provide 

discretion to the Administrator in 

implementing this definition. For 

example, the word ‘‘significant,’’ which 

is used to modify ‘‘indirect emissions,’’ 

is not defined. 

The definition includes both ‘‘direct’’ 

and ‘‘significant indirect’’ emissions 

related to the full fuel lifecycle. We 

consider direct emissions as those that 

are emitted from each stage of the full 

fuel lifecycle, and indirect emissions as 

those from second order effects that 

occur as a consequence of the full fuel 

lifecycle. For example, direct emissions 

for a renewable fuel would include 

those from the growing of renewable 

fuel feedstock, the distribution of the 

feedstock to the renewable fuel 

producer, the production of renewable 

fuel, the distribution of the finished fuel 

to the consumer, and the use of the fuel 

by the consumer as transportation fuel. 

Similarly, direct emissions associated 

with the baseline fuel would include 

extraction of the crude oil, distribution 

of the crude oil to the refinery, the 

production of gasoline and diesel from 

the crude oil, the distribution of the 

finished fuel to the consumer, and the 

use of the fuel by the consumer. Indirect 

emissions would include other 

emissions impacts that result from fuel 

production or use, such as changes in 

livestock emissions resulting from 

changes in livestock numbers, or shifts 

in acreage between different crop types. 

The definition of indirect emissions 

specifically includes ‘‘land use 

changes’’ which would include changes 

in the kind of usage that land is put to 

such as changes in forest, pasture, 

savannah, and crop use.269

In considering how to address land 

use changes in our lifecycle analysis, 

two distinct questions have been 

raised—whether to account for 

emissions that occur outside of the U.S., 

and under what circumstances land use 

change should properly be included in 

the lifecycle analysis. 

On the question of considering GHG 

emissions that occur outside of the U.S., 

it is important to be clear that including 

such emissions in the lifecycle analysis 

does not exercise regulatory authority 

over activities that occur solely outside 

the U.S., and does not raise questions of 

extra-territorial jurisdiction. EPA’s 

regulatory action involves classification 

of products either produced in the U.S. 

or imported into the U.S. EPA is simply 

assessing whether the use of these 

products in the U.S. satisfies 

requirements under the Clean Air Act 

for the use of designated volumes of 

renewable fuel, cellulosic biofuel, 

biomass-based diesel and advanced 

biofuel, as those terms are defined in the 

Act. Considering international 

emissions in determining the lifecycle 

GHG emissions of the domestically 

produced or imported fuel does not 

change the fact that the actual regulation 

of the product involves its use solely 

inside the U.S. 

When looking at the issue of 

international versus domestic 

emissions, it is important to recognize 

that a large variety of different activities 

outside the U.S. play a major part of the 

full fuel lifecycle of baseline and 

renewable fuels. For example, for 

baseline fuels (i.e., gasoline and diesel 

fuels used as transportation fuel in 

2005), GHG emissions associated with 

extraction and delivery of crude oil 

imported to the U.S. all have occurred 

overseas. In addition, for imported 

gasoline or diesel, all of the crude 

extraction and delivery emissions, as 

well as the emissions associated with 

refining and distribution of the finished 

product to the U.S., would have 

occurred overseas. For imported 

renewable fuel all of the emissions 

associated with feedstock production 

and distribution, processing of the 

feedstock into renewable fuel, and 

delivery of the finished renewable fuel 

to the U.S. would have occurred 

overseas. The definition of lifecycle 

greenhouse gas emissions makes it clear 

that EPA is to determine the aggregate 

emissions related to the ‘‘full’’ fuel 

lifecycle, including ‘‘all stages of fuel 

and feedstock production and 

distribution.’’ Thus, EPA could not, as 

a legal matter, ignore those parts of a 

fuel lifecycle that occur overseas. 

Drawing a distinction between GHG 

emissions that occur inside the U.S. as 

compared to emissions that occur 

outside the U.S. would dramatically 

alter the lifecycle analysis in a way that 

bears no apparent relationship to the 

purpose of this provision. The purpose 

of including lifecycle GHG thresholds in 

this statutory provision is to require the 

use of renewable fuels that achieve 

reductions in GHG emissions compared 

to the baseline. Drawing a distinction 

between domestic and international 

emissions would ignore a large part of 

the GHG emission associated with the 

different fuels, and would result in a 

GHG analysis of baseline renewable 

fuels that bears no relationship to the 

real world emissions impact of the fuels. 

The baseline would be significantly 

understated, given the large amount of 

imported crude used to produce 

gasoline and diesel, and the importation 

of finished gasoline and diesel, in 2005. 

Likewise, the emissions associated with 

imported renewable fuel would be 

understated, as it would only consider 

the emissions from distribution of the 

fuel to the consumer and the use of the 

fuel by the consumer, and would ignore 

both the emissions that occurred 

overseas as well as the emissions 

reductions from the intake of CO2 from 

growing of the feedstock. While large 

percentages of GHG emissions would be 

ignored, this would take place in a 

context where the global warming 

impact of emissions is irrespective of 

25024 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

where the emissions occur. Thus taking 

such an approach would essentially 

undermine the provision, and would be 

an arbitrary interpretation of the broadly 

phrased text used by Congress. 

While the emissions discussed above 

would more typically be considered 

direct emissions related to the full fuel 

lifecycle, there would also be no basis 

to cover just foreign direct emissions 

while excluding foreign indirect 

emissions. The text of the statute draws 

no such distinction, nor is there a 

distinction in achieving the purposes of 

the provision. GHG emissions impact 

global warming wherever they occur, 

and if the purpose is to achieve some 

reduction in GHG emissions in order to 

help address global warming, then 

ignoring GHG emissions because they 

are emitted outside our borders versus 

inside our borders interferes with the 

ability to achieve this objective. 

For example, domestic production of 

a renewable fuel could lead to indirect 

emissions, whether from land use 

changes or otherwise, some occurring 

within the U.S. and some occurring in 

other countries. Similarly, imported 

renewable fuel could have resulted in 

the same indirect emissions whether 

occurring in the country that produced 

the biofuel or in other countries. It 

would be arbitrary to assign the indirect 

emissions to the domestic renewable 

fuel but not to assign the identical 

indirect emissions that occur overseas to 

an imported product. 

Based on the above, EPA believes that 

the definition of lifecycle greenhouse 

gas emissions is properly interpreted as 

including all direct and significant 

indirect GHG emissions related to the 

full fuel lifecycle, whether or not they 

occur in the U.S. This applies to both 

the baseline lifecycle greenhouse 

emissions as well as the lifecycle 

greenhouse gas emissions for various 

renewable fuels. 

EPA recognizes, as discussed later, 

our estimates of domestic indirect 

emissions are more certain than our 

estimate of international indirect 

emissions. The issue of how to evaluate 

and weigh the various elements of the 

lifecycle analysis, and properly account 

for uncertainty in our estimates, is a 

different issue, however. The issue here 

is whether the definition of lifecycle 

greenhouse gas emissions is properly 

interpreted as including direct and 

significant indirect emissions that occur 

outside the U.S. as well as those that 

occur inside the U.S. 

As to the question of which land use 

changes should be included in our 

lifecycle analyses, a central element to 

focus on is the requirement that such 

indirect emissions be related to the full 

fuel lifecycle. The term ‘‘related to’’ is 

generally interpreted as providing a 

broad and expansive scope for a 

provision. It has routinely been 

interpreted as meaning to have a 

connection to or refer to a matter. To 

determine whether an indirect emission 

has the appropriate connection to the 

full fuel lifecycle, we must look at both 

the objectives of this provision as well 

as the nature of the relationship. 

In this case, EPA has used a global 

model that projects a variety of 

agricultural impacts that stem from the 

use of feedstocks to produce renewable 

fuel. We have estimated shifts in types 

of crops planted and increases in crop 

acres planted. There is a direct 

relationship between these shifts in the 

agricultural market as a consequence of 

the increased demand for biofuels in the 

U.S. Increased U.S. demand for biofuel 

feedstocks diverts these feedstocks from 

other competing uses, and also increases 

the price of the feedstock, thus spurring 

production. To the extent feedstocks 

like corn and soybeans are traded 

internationally, this combined impact of 

lower supply from the U.S. and higher 

commodity prices encourages 

international production to fill the gap. 

Our analysis uses country specific 

information to determine the amount, 

location, and type of land use change 

that would occur to meet this change in 

production patterns. The linkages are 

generally close, and are not extended or 

overly complex. While there is clearly 

significant uncertainty in determining 

the specific degree of land use change 

and the specific impact of those 

changes, there is considerable overall 

certainty as to the existence of the land 

use changes in general, the fact that 

GHG emissions will result, and the 

cause and effect linkage of these 

emissions impacts to the increased use 

of feedstock for production of renewable 

fuels. 

Overall, EPA is confident that it is 

appropriate to consider the estimated 

emissions from land use changes as well 

as the other indirect emissions as 

‘‘related to’’ the full fuel lifecycle, based 

on the reasonable technical basis 

provided by the modeling for the 

connection between the full fuel 

lifecycle and the indirect emissions, as 

well as for the determination that the 

emissions are significant. EPA believes 

uncertainty in the resulting aggregate 

GHG estimates should be taken into 

consideration, but that it would be 

inappropriate to exclude indirect 

emissions estimates from this analysis. 

Developing a reasonable estimate of 

these kinds of indirect emissions will 

allow for a reasoned evaluation of total 

GHG impacts, which is needed to 

promote the objectives of this provision, 

as compared to ignoring or not 

accounting for these indirect emissions. 

b. System Boundaries 

It is important to establish clear 

system boundaries in this analysis. By 

determining a common set of system 

boundaries, different fuel types can then 

be validly compared. As described in 

the previous section, we have assessed 

the direct and indirect GHG impacts in 

each stage of the full fuel lifecycle for 

biofuels and petroleum fuels. 

To capture the direct emissions 

impacts of feedstock production in our 

analysis, we included the agricultural 

inputs (e.g., the fuel used in the tractor, 

the energy used to produce and 

transport fertilizer to the field) needed 

to grow crops directly used in biofuel 

production. We also included the N2O 

emissions associated with agricultural 

sector practices used in biofuel 

production (including direct and 

indirect N2O emissions from synthetic 

fertilizer application, N fixing crops, 

crop residue, and manure management), 

as well as the land use change 

associated with converting land to grow 

crops directly used in biofuel 

production. To capture the indirect, or 

secondary, GHG emissions that result 

from biofuel feedstock production, we 

relied on the internationally accepted 

lifecycle assessment standards 

developed by the International 

Organization for Standardization (ISO). 

Examples of significant secondary 

impacts include the agricultural inputs 

associated with crops indirectly 

impacted by the use of feedstock for 

biofuel production (domestically and 

internationally), the emissions 

associated with land use change that are 

indirectly impacted by using feedstocks 

for biofuel production (e.g., to make up 

for lost U.S. exports), changes in 

livestock herd numbers that result from 

higher feed costs, and changes in rice 

methane emissions indirectly impacted 

by shifts in acres to produce feedstocks 

for biofuel production. These indirect or 

secondary impacts would not have 

occurred if it were not for the use of 

biomass to produce a biofuel. 

We did not include the infrastructure 

related GHG emissions (e.g., the energy 

needed to manufacture the tractor used 

on the farm) or the facility constructionrelated emissions (e.g., steel or concrete 

needed to construct a refinery). As part 

of the GHG analysis performed for 

RFS1, we performed a sensitivity 

analysis on expanding the corn 

production system to include farm 

equipment production to determine the 

impact it has on the overall results of 

our analysis. We found that including 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25025 

270 Greenhouse Gas Mitigation Potential in U.S. 

Forestry and Agriculture, EPA Document 430–R– 

05–006. See http://www.epa.gov/sequestration/ 

greenhouse_gas.html. 

farm equipment production energy use 

and emissions increases corn ethanol 

lifecycle energy use and GHG emissions 

and decreases the corn ethanol lifecycle 

GHG benefit as compared to petroleum 

gasoline by approximately 1%. 

Furthermore, to be consistent in the 

modeling if system boundaries are 

expanded to include production of 

farming equipment they should also be 

expanded to include producing other 

material inputs to both the ethanol and 

petroleum lifecycles. The net effect of 

this would be a slight increase in both 

the ethanol and petroleum fuel lifecycle 

results and a smaller or negligible effect 

on the comparison of the two. 

For this proposal, we have not yet 

incorporated secondary energy sector 

impacts, however we plan to have this 

analysis complete for the final rule. 

Additional details on the system 

boundaries are included in the DRIA 

Chapter 2. 

3. Modeling Framework 

Currently, no single model can 

capture all of the complex interactions 

associated with estimating lifecycle 

GHG emissions for biofuels, taking into 

account the ‘‘significant indirect 

emissions such as significant emissions 

from land use change’’ required by 

EISA. For example, some analysis tools 

used in the past focus on process 

modeling—the energy and resultant 

emissions associated with the direct 

production of a fuel at a petroleum 

refinery or biofuel production facility. 

But this is only one component in the 

production of the fuel. Clearly in the 

case of biofuels, impacts from and on 

the agricultural sector are important, 

because this sector produces feedstock 

for biofuel production. Commercial 

agricultural operations make many of 

their decisions based on an economic 

assessment of profit maximization. 

Assessment of the interactions 

throughout the agricultural sector 

requires an analysis of the commodity 

markets using economic models. 

However, existing economy wide 

general equilibrium economic models 

are not detailed enough to capture the 

specific agricultural sector interactions 

critical to our analysis (e.g., changes in 

acres by crop type) and would not 

provide the types of outputs needed for 

a thorough GHG analysis. As a result, 

EPA has used different tools that have 

different strengths for each specific 

component of the analysis to create a 

more comprehensive estimate of GHG 

emissions. Where no direct links 

between the different models exist, 

specific components and outputs of 

each are used and combined to provide 

an analytical framework and the 

composite lifecycle assessment results. 

As this is a new application of these 

modeling tools, EPA plans to organize 

peer review of our modeling approach. 

The individual models are described in 

the following sections and in more 

detail in Chapter 2 of the DRIA. 

To quantify the emissions factors 

associated with different steps of the 

production and use of various fuels 

(e.g., extraction of petroleum products, 

transport of feedstocks), we used the 

spreadsheet analysis tool developed by 

Argonne National Laboratories, the 

Greenhouse gases, Regulated Emissions, 

and Energy use in Transportation 

(GREET) model. This analysis tool 

includes the GHG emissions associated 

with the production and combustion of 

fossil fuels (diesel fuel, gasoline, natural 

gas, coal, etc.). These fossil fuels are 

used both in the production of biofuels, 

(e.g., diesel fuel used in farm tractors 

and natural gas used at ethanol plants) 

and could also be displaced by 

renewable fuel use in the transportation 

sector. GREET also estimates the GHG 

emissions estimates associated with 

electricity production required for 

biofuel and petroleum fuel production. 

For the agricultural sector, we also 

relied upon GREET to provide GHG 

emissions associated with the 

production and transport of agricultural 

inputs such as fertilizer, herbicides, 

pesticides, etc. While GREET provides 

direct GHG emissions estimates 

associated with the extraction-throughcombustion phases of fuel use, it does 

not capture some of the secondary 

impacts associated with the fuel, such 

as changes in the composition of feed 

used for animal production, which 

would be expected due to changes in 

cost. EPA addresses these secondary 

impacts through other models described 

later in this section. GREET has been 

under development for several years 

and has undergone extensive peer 

review through multiple updates. Of the 

available sources of information on 

lifecycle GHG emissions of fossil energy 

consumed, we believe that GREET offers 

the most comprehensive treatment of 

emissions from the covered sources. 

For some steps in the production of 

biofuels, we used more detailed models 

to capture some of the dynamic market 

interactions that result from various 

policies. Here, we briefly describe the 

different models incorporated into our 

analysis to provide specific details for 

various lifecycle components. 

To estimate the changes in the 

domestic agricultural sector (e.g., 

changes in crop acres resulting from 

increased demand for biofuel feedstock 

or changes in the number of livestock 

due to higher corn prices) and their 

associated emissions, we used the 

FASOM model, developed by Texas 

A&M University and others. FASOM is 

a partial equilibrium economic model of 

the U.S. forest and agricultural sectors. 

EPA selected the FASOM model for this 

analysis for several reasons. FASOM is 

a comprehensive forestry and 

agricultural sector model that tracks 

over 2,000 production possibilities for 

field crops, livestock, and biofuels for 

private lands in the contiguous United 

States. It accounts for changes in CO2, 

methane, and N2O from most 

agricultural activities and tracks carbon 

sequestration and carbon losses over 

time. Another advantage of FASOM is 

that it captures the impacts of all crop 

production, not just biofuel feedstock. 

Thus, as compared to some earlier 

assessments of lifecycle emissions, 

using FASOM allows us to determine 

secondary agricultural sector impacts, 

such as crop shifting and reduced 

demand due to higher prices. It also 

captures changes in the livestock market 

(e.g., smaller herd sizes that result from 

higher feed costs) and U.S. export 

changes. FASOM also has been used by 

EPA to consider U.S. forest and 

agricultural sector GHG mitigation 

options.270

To estimate the impacts of biofuels 

feedstock production on international 

agricultural and livestock production, 

we used the integrated FAPRI 

international models, developed by 

Iowa State University and the 

University of Missouri. These models 

capture the biological, technical, and 

economic relationships among key 

variables within a particular commodity 

and across commodities. FAPRI is a 

worldwide agricultural sector economic 

model that was run by the Center for 

Agricultural and Rural Development 

(CARD) at Iowa State University on 

behalf of EPA. The FAPRI models have 

been previously employed to examine 

the impacts of World Trade 

Organization proposals and changes in 

the European Union’s Common 

Agricultural Policy, to analyze farm bill 

proposals since 1984, and to evaluate 

the impact of biofuel development in 

the United States. In addition, the 

FAPRI models have been used by the 

USDA Office of Chief Economist, 

Congress, and the World Bank to 

examine agricultural impacts from 

government policy changes, market 

developments, and land use shifts. 

Although FASOM predicts land use 

and export changes in the U.S. due to 

25026 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

271Crutzen, P. J., Mosier, A. R., Smith, K. A., and 

Winiwarter, W.: N2O release from agro-biofuel 

production negates global warming reduction by 

replacing fossil fuels, Atmos. Chem. Phys., 8, 389– 

395, 2008. See http://www.atmos-chem-phys.net/8/ 

389/2008/acp-8-389-2008.pdf. 

greater demand for domestic biofuel 

feedstock, it does not assess how 

international agricultural production 

might respond to these changes in 

commodity prices and U.S. exports. The 

FAPRI model does predict how much 

crop land will change in other countries 

but does not predict what type of land 

such as forest or pasture will be 

affected. We used data analyses 

provided by Winrock International to 

estimate what land types will be 

converted into crop land in each 

country and the GHG emissions 

associated with the land conversions. 

Winrock has used 2001–2004 satellite 

data to analyze recent land use changes 

around the world that have resulted 

from the social, economic, and political 

forces that drive land use. Winrock has 

then combined the recent land use 

change patterns with various estimates 

of carbon stocks associated with 

different types of land at the state level. 

This international land use assessment 

is an important consideration in our 

lifecycle GHG assessment and is 

explained in more detail later in this 

section. 

To test the robustness of the FASOM, 

FAPRI and Winrock results, we are also 

evaluating the Global Trade Analysis 

Project (GTAP) model, a multi-region, 

multi-sector, computable general 

equilibrium model that estimates 

changes in world agricultural 

production. Maintained through Purdue 

University, GTAP projects international 

land use change based on the economics 

of land conversion, rather than using the 

historical data approach applied by 

FAPRI/Winrock. GTAP is designed to 

project changes in international land 

use as a result of the change in U.S. 

biofuel policies, based on the relative 

land use values of cropland, forest, and 

pastureland. The GTAP design has the 

advantage of explicitly modeling the 

competition between different land 

types due to a change in policy. As 

further discussed in Section VI.B.5.iv, 

GTAP has several disadvantages, some 

of which prevented its use for the 

proposal. We expect to correct several of 

these shortcomings between the 

proposed and final rules and therefore 

continue to evaluate how the GTAP 

model could be used as part of the final 

rule. 

The assessments provided in this 

proposal use the values provided by the 

Intergovernmental Panel on Climate 

Change (IPCC) to estimate the impacts of 

N2O emissions from fertilizer 

application. However, due to concern 

that this may underestimate N2O 

emissions from fertilizer application, 271

we are working with the CENTURY and 

DAYCENT models, developed by 

Colorado State University, to update our 

assessments. The DAYCENT model 

simulates plant-soil systems and is 

capable of simulating detailed daily soil 

water and temperature dynamics and 

trace gas fluxes (CH4, N2O, NOX and N2). 

The CENTURY model is a generalized 

plant-soil ecosystem model that 

simulates plant production, soil carbon 

dynamics, soil nutrient dynamics, and 

soil water and temperature. We 

anticipate the results of this new 

modeling work will be reflected in our 

assessments for the final rule. More 

description of this ongoing work is 

included in the Chapter 2 of the DRIA. 

To estimate the GHG emissions 

associated with renewable fuel 

production, we used detailed ASPENbased process models developed by 

USDA and DOE’s National Renewable 

Energy Laboratory (NREL). While 

GREET contains estimates for renewable 

fuel production, these estimates are 

based on existing technology. We expect 

biofuel production technology to 

improve over time, and we projected 

improvements in process technology 

over time based on available 

information. These projections are 

discussed in DRIA Chapter 4. We then 

utilized the ASPEN-based process 

models to assess the impacts of these 

improvements. We also cross-checked 

the ASPEN-based process model 

predictions by comparing them to a 

number of industry sources and other 

modeling efforts that estimate potential 

improvements in ethanol production 

over time, including the Biofuel Energy 

Systems Simulator (BESS) model. BESS 

is a software tool developed by the 

University of Nebraska that calculates 

the energy efficiency, greenhouse gas 

(GHG) emissions, and natural resource 

requirements of corn-to-ethanol biofuel 

production systems. We used the 

GREET model to estimate the GHG 

emissions associated with current 

technology as used by petroleum 

refineries, because we do not expect 

significant changes in petroleum 

refinery technology. 

We used the EPA-developed Motor 

Vehicle Emission Simulator (MOVES) to 

estimate vehicle tailpipe GHG 

emissions. The MOVES modeling 

system estimates emissions for on-road 

and nonroad sources, covers a broad 

range of pollutants, and allows multiple 

scale analysis, from fine-scale analysis 

to national inventory estimation. 

Finally, for the FRM we intend to use 

an EPA version of the Energy 

Information Administration’s National 

Energy Modeling System (NEMS) to 

estimate the secondary impacts on the 

energy market associated with increased 

renewable fuel production. NEMS is a 

modeling system that simulates the 

behavior of energy markets and their 

interactions with the U.S. economy by 

explicitly representing the economic 

decision-making involved in the 

production, conversion, and 

consumption of energy products. NEMS 

can reflect the secondary impacts that 

greater renewable fuel use may have on 

the prices and quantities of other 

sources of energy, and the greenhouse 

gas emissions associated with these 

changes in the energy sector. It was not 

possible to complete this analysis in 

time for the NPRM 

While EPA is using state-of-the-art 

tools available today for each of the 

lifecycle components considered, using 

multiple models necessitates integrating 

these models and, where possible, 

applying a common set of assumptions. 

As discussed later in this section, this 

is particularly important for the two 

agricultural sector models, FASOM and 

FAPRI, which are being used in 

combination to describe the agricultural 

sector impacts domestically and 

internationally. As described in more 

detail in the DRIA Chapter 5, we have 

worked with the FAPRI and FASOM 

models to align key assumptions. As a 

result, the projected agricultural impacts 

described in Section IX are relatively 

consistent across both models. One 

outstanding issue is the differences 

between the modeling results associated 

with increased soybean-based biodiesel 

production. We intend to further refine 

the soybean biodiesel scenarios for the 

final rule. Additional details on all of 

the models used can be found in DRIA 

Chapter 2. Finally, as noted earlier, we 

are planning to have a number of 

aspects of our modeling framework peer 

reviewed before finalizing these 

regulations. In the sections below, we 

have identified specific peer review 

plans. 

4. Treatment of Uncertainty 

While EPA believes the methodology 

presented here represents a robust and 

scientifically credible approach, we 

recognize that some calculations of GHG 

emissions are relatively straightforward, while others are not. The 

direct, domestic emissions are relatively 

well known. These estimates are based 

on well-established process models that 

can relatively accurately capture 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25027 

272 2006 Intergovernmental Panel on Climate 

Change (IPCC) Guidelines for National Greenhouse 

Gas Inventories, Volume 4, Chapter 11, N2O 

emissions from Managed Soils, and CO2 Emissions 

from lime and Urea Application. See http:// 

www.ipcc-nggip.iges.or.jp/public/2006gl/vol4.html. 

273Crutzen et al., 2008. 

emissions impacts. For example, the 

energy and GHG emissions used by a 

natural gas-fired ethanol plant to 

produce one gallon of ethanol can be 

calculated through direct observations, 

though this will vary somewhat between 

individual facilities. The indirect 

domestic emissions are also fairly well 

understood; however, these results are 

sensitive to a number of key 

assumptions (e.g., current and future 

corn yields). We address uncertainty in 

this area by testing the impact of 

changing these assumptions on our 

results. Finally, the indirect, 

international emissions are the 

component of our analysis with the 

highest level of uncertainty. For 

example, identifying what type of land 

is converted internationally and the 

emissions associated with this land 

conversion are critical issues that have 

a large impact on the GHG emissions 

estimates. We address this uncertainty 

by using sensitivity analyses to test the 

robustness of the results based on 

different assumptions. We also identify 

areas of additional work that will be 

completed prior to the final rulemaking. 

For example, while we utilized an 

approach using comprehensive 

agricultural sector models and recent 

satellite data to determine the emissions 

resulting from international land use 

impacts, we are also considering an 

alternative methodology (the analyses 

using GTAP) that estimates changes in 

land use based on the relative land use 

values of cropland, forest, and 

pastureland. Additionally, we are 

considering country-specific 

information which may allow us to 

better predict specific trends in land use 

such as the degree to which marginal or 

abandoned pasture land will need to be 

replaced if used instead for crop 

production. In addition to the 

sensitivity analysis approach, we will 

also explore options for more formal 

uncertainty analyses for the final rule to 

the extent possible. However, formal 

uncertainty analyses generally include 

an assumption of a statistically based 

distribution of likely outcomes. In the 

time available for developing this 

proposal, we have not developed an 

analytical technique which allows us to 

determine the likelihood of a range of 

possible outcome across the wide range 

of critical factors affecting lifecycle GHG 

assessment. We specifically ask for 

recommendations on how best to 

conduct a sound, statistically based 

uncertainty analysis for the final rule. 

Despite the uncertainty associated 

with international land use change, we 

would expect at least some international 

land use change to occur as demand for 

crop land increases as a result of this 

rule. Furthermore, the conversion of 

crop land will lead to GHG emission 

from land conversion that must be 

accounted for in the calculation of 

lifecycle GHG emissions. As discussed 

above, we believe that uncertainty in the 

effects and extent of land use changes is 

not a sufficient reason for ignoring land 

use change emissions. Although 

uncertainties are associated with these 

estimates, it would be far less 

scientifically credible to ignore the 

potentially significant effects of land use 

change altogether than it is to use the 

best approach available to assess these 

known emissions. We anticipate that 

comment and information received in 

response to this proposal as well as 

additional analyses will improve our 

assessment of land use impacts for the 

final rule. Finally, we note that further 

research on key variables will result in 

a more robust assessment of these 

impacts in the future. 

5. Components of the Lifecycle GHG 

Emissions Analysis 

As described previously, GHG 

emissions from many stages of the full 

fuel lifecycle are included within the 

system boundaries of this analysis. 

Details on how these emissions were 

calculated are included in the DRIA 

Section 2. This section highlights the 

key questions that we have attempted to 

address in our analysis. In addition, this 

section identifies some of the key 

assumptions that influence the GHG 

emissions estimates in the following 

section. 

a. Feedstock Production 

Our analysis addresses the lifecycle 

GHG emissions from feedstock 

production by capturing both the direct 

and indirect impacts of growing corn, 

soybeans, and other renewable fuel 

feedstocks. For both domestic and 

international agricultural feedstock 

production, we analyzed four main 

sources of GHG emissions: agricultural 

inputs (e.g., fertilizer and energy use), 

fertilizer N2O, livestock, and rice 

methane. (Emissions related to land use 

change are discussed in the next 

section). 

As described in Section IX.A, EPA 

uses FASOM to model domestic 

agricultural sector impacts and uses 

FAPRI to model international 

agricultural sector impacts. However, 

we also recognize that these emission 

estimates rely on a number of key 

assumptions, including crop yields, 

fertilizer application rates, use of 

distiller grains and other co-products, 

and fertilizer N2O emission rates. As 

described in the following sections, we 

have used sensitivity analyses to test the 

impact of changing these assumptions 

on our results. 

i. Domestic Agricultural Sector Impacts 

Agricultural Sector Inputs: GHG 

emissions from agricultural sector 

inputs (chemical and energy) are 

determined based on output from 

FASOM combined with default factors 

for GHG emissions from GREET. Fuel 

use emissions from GREET include both 

the upstream emissions associated with 

production of the fuel and downstream 

combustion emissions. Inputs are based 

on historic rates by region and include 

projected increases to account for yield 

improvements over time. This yield 

increase does not capture changes due 

to cropping practices such as shifts to 

corn-after-corn rotations. 

N2O Emissions: FASOM estimates 

N2O emissions from fertilizer 

application and nitrogen fixing crops 

based on the amount of fertilizer used 

and different regional factors to 

represent the percent of nitrogen (N) 

fertilizer applied that result in N2O 

emissions. This approach is consistent 

with IPCC guidelines for calculating 

N2O emissions from the agricultural 

sector.272 A recent paper 273 raised the 

question of whether N2O emissions are 

significantly higher than previously 

estimated. To better understand this 

issue, we are working with Colorado 

State University to analyze N2O 

emissions. Specifically, Colorado State 

University will provide several key 

refinements for a re-analysis of land use 

and cropping trends and GHG emissions 

in the FASOM assessment, including: 

• Direct N2O emissions based on 

DAYCENT simulations with an 

accounting of all N inputs to 

agricultural soils, including mineral N 

fertilizer, organic amendments, 

symbiotic N fixation, asymbiotic N 

fixation, crop residue N, and 

mineralization of soil organic matter. 

Colorado State University will provide 

(1) the total emission rate on an acre 

basis for each simulated bioenergy crop 

in the 63 FASOM regions and (2) a total 

emissions for each N source. 

• Indirect N2O emissions on a per 

acre basis using results from DAYCENT 

simulations of volatilization, leaching 

and runoff of N from each bioenergy 

crop included in the analysis for the 63 

FASOM regions, combined with IPCC 

25028 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

274Salil Arora, May Wu, and Michael Wang, 

‘‘Update of Distillers Grains Displacement Ratios for 

Corn Ethanol Life-Cycle Analysis,’’ September 

2008. See http://www.transportation.anl.gov/pdfs/ 

AF/527.pdf. 

factors for the N2O emission associated 

with the simulated N losses. 

The analyses with updated N2O 

estimates are not yet complete and are 

not included in this proposal. We 

expect to complete these analyses for 

the final rule. 

Livestock Emissions: GHG emissions 

from livestock have two main sources: 

enteric fermentation and manure 

management. Enteric fermentation 

produces methane emissions as part of 

the normal digestive processes in 

animals. The FASOM modeling reflects 

changes in livestock enteric 

fermentation emissions due to changes 

in livestock herds. As more corn is used 

in producing ethanol the price of corn 

increases, driving changes in livestock 

production costs and demand. The 

FASOM model predicts reductions in 

livestock herds. IPCC factors for 

different livestock types are applied to 

herd values to get GHG emissions. The 

management of livestock manure can 

produce methane and N2O emissions. 

Methane is produced by the anaerobic 

decomposition of manure. N2O is 

produced as part of the nitrogen cycle 

through the nitrification and 

denitrification of the organic nitrogen in 

livestock manure and urine. FASOM 

calculates these manure management 

emissions based on IPCC default factors 

for emissions factors from the different 

types of livestock and management 

methods. Manure management 

emissions are projected to be reduced as 

a result of lower livestock animal 

numbers. Use of distiller grains (DGs), 

as discussed in Section VI.B.5.b, has 

been shown to decrease methane 

produced from enteric fermentation if 

replacing corn as animal feed.274 This 

effect is not currently captured in the 

models but will be considered for the 

final rule. 

Methane from Rice: Most of the 

world’s rice, and all rice in the United 

States, is grown in flooded fields. When 

fields are flooded, aerobic 

decomposition of organic material 

gradually depletes most of the oxygen 

present in the soil, causing anaerobic 

soil conditions. Once the environment 

becomes anaerobic, methane is 

produced through anaerobic 

decomposition of soil organic matter by 

methanogenic bacteria. FASOM predicts 

changes in rice acres resulting from the 

RFS2 program and calculates changes in 

methane emissions using IPCC factors. 

ii. International Agricultural Sector 

GHG Impacts 

Agricultural Sector Inputs: The FAPRI 

model does not directly provide an 

assessment of the GHG impacts of 

changes in international agricultural 

practices (e.g., changes in fertilizer load 

and fuels usage), however it does 

predict changes in the land area and 

production by crop type and by country. 

We therefore determined international 

fertilizer and energy use based on 

international data collected by the Food 

and Agriculture Organization (FAO) of 

the United Nations and the International 

Energy Agency (IEA). We used the 

historical trends based on these FAO 

and IEA data to project chemical and 

energy use in 2022. Additional details 

on the data used are included in DRIA 

Chapter 2. We intend to review input 

changes required to increase yields for 

the final rule and request comment on 

the extent to which historic trends 

adequately project what could occur in 

2022 or what alternative assumptions 

should be made and the bases for these 

assumptions. For example, will changes 

in farming practices or seed varieties 

likely result in significantly different 

impacts on fertilizer use internationally 

than suggested by recent trends? 

Additionally, we intend to have the 

selection and application of this data 

peer reviewed before the final rule. 

N2O Emissions: For international N2O 

emissions from crops, we apply the 

IPCC emissions factors based on total 

amount of fertilizer applied and N2O 

impacts of crop residue by type of crop 

produced. As noted above, we are also 

working with Colorado State University 

to update these factors as part of the 

final rule analysis. Additional details on 

the factors used are included in DRIA 

Chapter 2. 

Livestock Emissions: Similar to 

domestic livestock impacts associated 

with an increase in biofuel production, 

FAPRI model predicts international 

changes in livestock production due to 

changes in commodity prices. The GHG 

impacts of these livestock changes, 

including enteric fermentation and 

manure management GHG emissions, 

were included in our analysis. Unlike 

FASOM, the FAPRI model does not 

have GHG emissions built in and 

therefore livestock GHG impacts were 

based on activity data provided by the 

FAPRI model (e.g., number and type of 

livestock by country) multiplied by 

IPCC default factors for GHG emissions. 

We seek comments on the extent to 

which the use of this methodology is 

appropriate. 

Rice Emissions: To estimate rice 

emission impacts internationally, we 

used the FAPRI model to predict 

changes in international rice production 

as a result of the increase in biofuels 

demand in the U.S. Since FAPRI does 

not have GHG emissions factors built 

into the model, we applied IPCC default 

factors by country based on predicted 

changes in rice acres. We seek 

comments on this methodology. 

b. Land Use Change 

We are also addressing GHG 

emissions associated with land use 

changes that occur domestically and 

internationally as a result of the increase 

in renewable fuels demand in the U.S. 

Key questions we address in this 

analysis include the land area converted 

to crop production, where those acreage 

changes occur, lands types converted, 

and the GHG emission impacts 

associated with different types of land 

conversion. 

EPA recognizes that analyzing 

international impacts of land use change 

can introduce additional uncertainty to 

the GHG emissions estimates. At this 

time, we do not have the same quality 

of data for international crop production 

and projected future trends as we do for 

the United States. For example, 

prediction of the economic and 

geographic development of developing 

country agricultural systems is far more 

difficult than prediction of future U.S. 

agricultural development. The U.S. has 

a very mature agriculture system in 

which the high quality agricultural 

lands are already under production and 

the infrastructure to move crops to 

market is already in place. This is not 

necessarily the case in other countries. 

Some very large countries expected to 

play a significant role in future 

agricultural production are still 

developing their agricultural system. 

Brazil, for example, has vast areas of 

land that may be suitable for 

commercial agricultural production that 

would allow for significant expansion in 

crop lands. One of the restraints on 

expansion is the relative lack of 

infrastructure (e.g., road and rail 

systems) that would allow shipment of 

expanded crop production to market. 

Identifying what type of land is 

converted internationally and the 

emissions associated with this land 

conversion can significantly affect our 

assessment of GHG impacts. We present 

a range of results for differences in these 

and other assumptions in Section 

VI.C.2, and we seek comment on our 

approach so that the final rule will use 

the best science to provide credible 

estimates of lifecycle GHG emissions for 

each biofuel. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25029 

275Salil et al., 2008. 

276Note that these same assumptions apply in 

both the reference case and the control cases. 

i. Amount of Land Converted 

The main question regarding the 

amount of new land needed to meet an 

increasing demand for biofuels hinges 

on assumptions about the 

intensification of existing production 

versus expansion of production to other 

lands. This interaction is driven by the 

relative costs and returns associated 

with each option, but there are other 

factors as described below. 

Co-Products: One factor determining 

the amount of new crop acres required 

under an increased biofuel scenario is 

the treatment of co-products. For 

example, distillers grains (DGs) are the 

major co-product of dry mill ethanol 

production that is also used as animal 

feed. Therefore, using the DGs as an 

animal feed to replace the use of corn 

tends to offset the loss of corn to ethanol 

production, and reduces the need to 

grow additional corn to feed animals. As 

the renewable fuels industry expands, 

the handling and use of co-products is 

also expanding. Some uncertainty is 

associated with how these co-products 

will be used in the future (e.g., whether 

it can be reformulated for higher 

incorporation into pork and poultry 

diets, whether it will be dried and 

shipped long distances, whether 

fractionation will become widespread). 

Both our FASOM and FAPRI models 

account for the use of DGs in the 

agricultural sector. The FASOM and 

FAPRI models both assume that a 

pound of co-product would displace 

roughly a pound of feed. However, a 

recent paper by Argonne National 

Laboratory 275 estimates that 1 pound of 

DGs can displace more than a pound of 

feed due to the higher nutritional value 

of DGs compared to corn. 

The Argonne replacement ratios do 

not take into account the dynamic least 

cost feed decisions faced by livestock 

producers. The actual use of DGs will 

depend on the maximum inclusion rates 

for each type of animal (based on the 

digestibility of DGs), the displacement 

ratio for each type of animal (based on 

DGs energy and protein content), and 

the adoption rate (based on the feed 

value relative to price). Furthermore, as 

world vegetable oil prices increase, dry 

mill ethanol producers will have an 

incentive to extract the corn oil from the 

DGs. This step changes the nutritional 

content of the DGs, which results in 

different replacement rates than the 

ones currently used in FASOM or 

described by Argonne. As we plan to 

evaluate and incorporate a least cost 

feed rationing approach for the final 

rule, we invite comment on the 

expected future uses of DGs and their 

displacement ratios. 

Crop Yields: Assumptions about 

yields and how they may change over 

time can also influence land use change 

predictions. Domestic yields were based 

on USDA projections, extrapolated out 

to 2022. In 2022, we estimate that the 

U.S. average corn yield will be 

approximately 180 bushels/acre (a 1.6% 

annual increase consistent with recent 

trends) and average U.S. soybean yields 

will be approximately 50 bushels per 

acre (a 0.4% annual increase).276 Using 

the FASOM model, we conducted a 

sensitivity analysis on the impact of 

higher and lower yields in the U.S. 

Details on this scenario are included in 

DRIA Chapter 5.1. International yields 

changes are also based on the historic 

trends. The FAPRI model contains 

projected yields and yield growths that 

are generally lower in other countries 

compared to the U.S. We request 

comment on the projected increase in 

crop yields in the U.S (including 

consideration of how emerging seed 

types might be expected to increase 

average crop yields). We also request 

comment on the use of historical trends 

to predict future agricultural production 

in other countries and request 

information on alternative 

methodologies and supporting data that 

would allow us to base our predictions 

on alternative assumptions. 

The FASOM and FAPRI models 

currently do not take into account 

changes in productivity as crop 

production shifts to marginal acres or 

the impact of price induced yield 

changes on land use change. We would 

expect these two factors could work in 

opposite directions and therefore could 

tend to offset each other’s impacts. 

Marginal acres in fully developed 

agricultural systems are expected to 

have lower yields, because most 

productive acres are already under 

cultivation. This may not be the case in 

developing systems where prime 

agricultural lands are not currently in 

full production due to, for example, lack 

of supporting infrastructure. Changes in 

agricultural inputs (e.g., fertilizer, 

pesticides) can also change crop yield 

per acre. Higher commodity prices 

might provide an incentive to increase 

production in existing acres. If the costs 

of increasing productivity on existing 

land were minimal relative to the value 

of the increased production, then 

agricultural landowners would 

presumably adopt these productivityenhancing actions under the reference 

case. Although it is reasonable to 

assume a trend wherein some 

productivity-enhancing practices may 

become profitable if commodity prices 

are high enough such as might occur as 

the result of increased biofuel 

production, it is not clear that farmers 

would find significant increases in 

production per acre profitable. If crop 

yields either domestically or 

international are significantly impacted 

by higher commodity prices driven by 

general increase in worldwide demand, 

this could affect our assessment of land 

use impacts and the resulting GHG 

emissions due to increased biofuel 

demand in the U.S. However, as 

described in Section IX, the change in 

commodity prices associated with the 

increase in U.S. biofuel as a result of the 

EISA mandates are very small and 

perhaps not large enough to induce 

significant increased yield changes. We 

invite comment on projected yields and 

the potential impact of increased use of 

marginal lands and price induced yield 

changes. For the final rule we plan to 

explicitly model the impact of price 

induced yield changes. 

Land Conversion Costs: The assumed 

cost associated with different types of 

land conversion can also play a key role 

in determining how much land will be 

converted. In FASOM, the decision to 

convert land from pasture or forest to 

cropland is based on whether the 

landowner can increase the net present 

value of expected returns through 

conversion (including any costs of 

conversion). Among other things, the 

decision to convert land depends on 

regional yields, costs, and other factors 

affecting profitability and on the returns 

to alternative land uses. In other words, 

FASOM assumes that land conversion is 

based on maximizing profits rather than 

minimizing costs. Additional details on 

land conversions costs incorporated in 

FASOM are included in DRIA Chapter 

2. 

FAPRI does not explicitly model land 

conversion costs, however the 

international production supply curves 

used by the FAPRI model implicitly 

take into account conversion costs. 

FAPRI’s supply curves are based on 

historical responses to price changes, 

which take into account the conversion 

costs of land, based on expected future 

returns associated with land conversion. 

Thus, we believe that our assessments of 

international land use changes are based 

on economic land-use decisions. 

ii. Where Land is Converted 

The first step in determining what 

domestic and international land will be 

converted due to biofuels production is 

to estimate the extent to which the 

increased demand for biofuel feedstock 

25030 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

will be met through increased U.S. 

agriculture production or reductions in 

U.S. exports. 

This question has several 

implications. For example, U.S. 

agriculture production is typically more 

energy and input intensive but has 

higher yields than agricultural 

production in other parts of the world. 

This implies that increased production 

in the U.S. has higher input GHG 

emission impacts but lower land use 

change impacts compared to overseas 

production. In addition, the types of 

land where agriculture would expand 

would be different in the U.S. vs. other 

parts of the world. 

EPA’s analysis relies on FASOM 

predictions to represent changes in the 

U.S. agricultural sector, including land 

use, and on FAPRI to predict the 

resulting international agricultural 

sector impacts including the amount of 

additional cropland needed under 

different scenarios. The impact on the 

international agricultural sector is 

highly dependent on the U.S. export 

assumptions. As the FASOM model was 

used to represent domestic agricultural 

sector impacts with an assumed export 

picture, the international agricultural 

sector impacts from FAPRI needed to be 

based on a consistent set of export 

assumptions. We worked with FASOM 

and FAPRI modelers to ensure this 

consistency. This involved coordinating 

crop yields, ethanol yields and coproduct use, assumptions regarding CRP 

acres, a consistent export response, and 

a consistent livestock demand and feed 

use in both models. 

As shown in Chapter 2 of the DRIA, 

coordination of assumptions has 

generated a consistent export picture 

response from both the FASOM and 

FAPRI model for the majority of biofuel 

and feedstock scenarios considered. 

Differences in responses in the biodiesel 

scenario remain between the two 

models. FASOM assumes more 

biodiesel will come from new soybean 

acres (but total domestic acres are 

relatively constant as reductions in 

other crops offset the increase in 

soybean acres). In comparison, FAPRI 

contains more types of oil seed crops 

and has a more elastic demand in the 

soybean oil market. The FAPRI model 

also allows for some corn oil 

fractionation from DGs, which can be 

used as a substitute for soybean oil. The 

FASOM model predicts a larger change 

in net exports than the FAPRI model. 

Since we are using the FAPRI model as 

the basis for estimating international 

land use changes, we may be 

underestimating the international land 

use change emissions associated with 

soybean based biodiesel. For the final 

rule, EPA will work, in particular, to 

resolve the differences in soybean 

production impact between the models. 

This, too, may modify our assessment of 

the biodiesel lifecycle GHG emissions. 

Due to the wide range of carbon and 

biomass properties associated with land 

in different parts of the world, the 

location of crop conversion is also 

important to our lifecycle analysis. For 

example, an average acre of forest in 

Southeast Asia stores a much larger 

quantity of carbon than a typical acre of 

forest in Northern Europe. The FAPRI 

model provides estimates of the acreage 

change by country and crop that result 

from a decrease in U.S. exports due to 

the increase in U.S. biofuel demand. 

These estimates are based on historic 

responsiveness to changes in prices in 

other countries. Implicit in these supply 

curves are the costs associated with 

converting new land to crop production 

and the relative competitiveness of each 

country to increase production based on 

production costs, yields, transportation 

costs, and currency fluctuations. FAPRI 

also includes in its baseline projections 

of future population growth, GDP 

growth, and other macroeconomic 

changes. FAPRI also takes into account 

the fact that not all U.S. exports will 

need to be made up in international 

production, as there is a small decreases 

in demand due to shifts in crop 

production and higher prices. 

iii. What Type of Land is Converted 

In the same way that the location of 

land conversion is important, the type 

of land that is converted is critical to the 

magnitude of impact on the GHG 

emissions associated with biofuel 

production. For example, the 

conversion of rainforest results in a 

much larger increase in GHG emissions 

than the conversion of grassland. There 

are several options for determining what 

type of land will be converted to crop 

acreage. One option is to model land 

rental rates for different types of land 

(e.g., forest, pasture, and crop 

production), and allow the model to 

choose the type of land that is expected 

to have the highest net returns. This 

approach is used by FASOM on the 

domestic side. Another option is to use 

historical land conversion trends in a 

given country or region. The FAPRI/ 

Winrock approach uses this approach 

for international land use conversion. 

Domestic: The FASOM model 

includes competition between land 

types, agriculture, pasture, and forest 

land. The interaction is based on 

providing the highest rate of return 

across the different land types. 

Therefore domestically we have the 

ability to explicitly model what types of 

land would be converted to increased 

agriculture based on the rates of return 

for different land types for the 63 

regions in FASOM. For this draft 

proposal we incorporated the 

agricultural component (which includes 

both existing cropland and pasture) of 

the FASOM model, but not the forestry 

component (see Section IX.A for 

explanation). Therefore, this analysis 

assumes that all additional cropland 

predicted by FASOM comes from 

pasture. As we incorporate the forestry 

component for the final rule analysis we 

would expect to see more interaction 

between the forestry and agriculture 

sector such that there may be 

conversion of forest to agriculture based 

on additional cropland needed. While 

we do not know if forest will be 

converted to cropland or the extent that 

this might occur, if domestic forests 

were converted to cropland, we would 

expect domestic GHG emissions would 

increase. This work will be incorporated 

for our final rule. 

International: Basing land use change 

on the economics and rates of return of 

different land uses offers advantages for 

capturing potential future land use 

changes. However, the only model 

potentially capable of fully 

incorporating this calculation 

internationally, GTAP, is still in the 

process of being updated and modified 

for this purpose. Thus, EPA has chosen 

to use historical patterns as identified 

by satellite images to estimate future 

land conversion. This approach is 

referred to here as the FAPRI/Winrock 

approach because it relies on the 

integration of each of these tools. 

EPA believes that FAPRI/Winrock is a 

scientifically credible modeling 

approach at this time. However, we will 

continue to work with the GTAP model 

to help test the results generated by our 

primary approach. 

FAPRI/Winrock 

Since FAPRI does not contain 

information on what type of land is 

being converted into cropland, we 

worked with Winrock International, a 

global nonprofit organization, to address 

this question. A key advantage of 

Winrock is that they can accurately 

measure and monitor trends in forest 

and land use change, forest carbon 

content, biodiversity, and the impact of 

infrastructure development. 

Furthermore, several of the Winrock 

staff were involved in the development 

of the IPCC land use change good 

practice guidance and are widely 

recognized as the leaders in this field. 

Using satellite data from 2001–2004, 

Winrock provided a breakdown of the 

types of land that have been converted 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25031 

277U.S. Geological Survey MODIS Data Set 

Documentation. See http://edcdaac.usgs.gov/modis/ 

mod12q1v4.asp. 

278See for example ‘‘Mitigation of GHG emissions 

using sugarcane bio-ethanol—Working Paper’’ by 

Isaias C. Macedo and Joaquim E. A. Seabra, and 

‘‘Prospects of the Sugarcane Expansion in Brazil: 

Impacts on Direct and Indirect Land Use Changes— 

Working Paper’’ by Andre Nassar et al., both 

received by EPA October 13, 2008. 

into cropland for a number of key 

agriculturally producing countries based 

on the International GeosphereBiosphere Programme (IGBP).277 The 

IGBP land cover list includes eleven 

classes of natural vegetation, three 

classes of developed and mosaic lands, 

and three classes of non-vegetated 

lands. The natural vegetation units 

distinguish evergreen and deciduous, 

broadleaf and needle-leaf forests, mixed 

forests, where mixtures occur; closed 

shrublands and open shrublands; 

savannas and woody savannas; 

grasslands; and permanent wetlands of 

large areal extent. The three classes of 

developed and mosaic lands distinguish 

among croplands, urban and built-up 

lands, and cropland/natural vegetation 

mosaics. Classes of non-vegetated land 

cover units include snow and ice; 

barren land; and water bodies. Winrock 

aggregated these categories into five 

similar classes: five classes of forest 

were combined into one, two classes of 

savanna were combined into one, and 

two classes of shrubland were combined 

into one. The final land cover categories 

for this analysis are forest, cropland, 

grassland, savanna, and shrubland. The 

rest of the IGBP categories not of interest 

to this analysis were reclassified into 

the background. The satellite data 

represents different types of land cover, 

which we are using as a proxy for land 

use. 

A key strength of this approach is that 

satellite information is based on 

empirical data instead of modeled 

predictions. Furthermore, it is 

reasonable to assume that recent land 

use changes have been driven largely by 

economics and recent historical patterns 

will continue in the future absent major 

economic or land use regime shifts 

caused, for example, by changes in 

government policies. We are using the 

FAPRI model to predict where in the 

world, based on economic conditions, 

the most likely increase in agriculture 

production will occur as a result of the 

EISA mandates. We are then using the 

historical satellite data to address the 

key question: If additional land is 

needed for crop production in a 

particular country, what type of land 

will be used? The Winrock analysis 

addresses this question by calculating 

the weighted average type of land that 

was converted to cropland between 

2001 and 2004. Essentially, we are using 

the Winrock data to determine the type 

of land that is most likely to be 

converted to cropland, should 

additional acres be needed as predicted 

by FAPRI. 

Table VI.B.5–1 shows the percentage 

of land converted to cropland between 

2001 and 2004 according to the Winrock 

satellite data analysis for the countries 

currently available. We use these 

percentages to calculate a weighted 

average of the types of land converted 

into cropland. For example, if FAPRI 

predicts that one additional acre of 

cropland will be brought into 

production in Argentina, we used the 

Winrock data to estimate that 8% on 

average of that acre will come from 

forest, 40% of that acre will come from 

grassland, 45% of that land will come 

from savanna, and 8% of that land will 

come from shrubland. Using GTAP 

might result in different percentage 

weights. 

TABLE VI.B.5–1—TYPES OF LAND CONVERTED TO CROPLAND BY COUNTRY

[In percent] 

Country Forest Grassland Savanna Shrub 

Argentina .......................................................................................................... 8 40 45 8 

Brazil ................................................................................................................ 4 18 74 4

China ................................................................................................................ 17 38 23 21 

EU .................................................................................................................... 27 16 36 21 

India ................................................................................................................. 7 7 33 53

Indonesia ......................................................................................................... 34 5 58 4 

Malaysia ........................................................................................................... 74 3 19 3 

Nigeria .............................................................................................................. 4 56 36 4 

Philippines ........................................................................................................ 49 5 44 3 

South Africa ..................................................................................................... 10 22 53 15 

Source: Winrock Satellite Data (2001–2004). 

We are assuming that the weighted 

average, resulting from agriculture 

demand as well as other possible 

drivers, is a reasonable estimate of the 

land use change attributable to 

increased agricultural demand. A 

shortcoming of this approach is that it 

assumes that when new crop acres are 

needed to meet increased agricultural 

demand these crop acres will follow the 

average pattern of recent historical land 

conversion, recognizing that this pattern 

is based on a variety of drivers of land 

use change, not all of which are 

associated with agricultural demand. 

This approach is not able to isolate from 

the historical pattern the land use 

changes stemming just from increased 

agricultural demand. For example, it is 

likely that in some cases trees are being 

removed from forests for the value of the 

wood. However, having removed 

valuable wood, additional clearing may 

occur to allow the land to be used for 

pasture or cropland. In that case the 

GHG emissions associated with the 

removal of the trees would not occur as 

a consequence of increased agricultural 

demand, but as a consequence of 

increased demand for the wood, while 

the GHG emissions associated with the 

additional clearing would occur as a 

consequence of the agricultural demand. 

As a result, the Winrock data also 

does not distinguish between the landuse impacts associated with one crop 

versus another. Indeed, at least in the 

case of sugarcane production in Brazil, 

a number of researchers argue that 

expanded sugarcane production is likely 

to occur in significant part through the 

use of degraded or abandoned pasture 

land without additional land use 

impact.278 These research reports 

suggest that general historical trends in 

land use change to grow crops in Brazil 

may not pertain to expected growth in 

sugarcane production. Ideally, an 

analysis of a U.S. biofuels policy’s 

influence on land use change would 

25032 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

279 GTAP Land Cover Data (2000–2001). 280Searchinger et al., 2008. 

281 2006 IPCC Guidelines for National Greenhouse 

Gas Inventories, Volume 4, Agriculture, Forestry 

and Other Land Use (AFOLU). See http://www.ipccnggip.iges.or.jp/public/2006gl/vol4.html. 

282See ftp://www.daac.ornl.gov/data/global_soil/ 

IsricWiseGrids. 

283 2006 IPCC Guidelines for National Greenhouse 

Gas Inventories, Volume 4, Section 5.3.3.4. 

model the marginal impact that U.S. 

biofuel would have on land use and 

land use change in addition to baseline 

land use change. Use of historic land 

use change data is capturing some of 

this baseline land use change. 

Comments are requested on our 

approach of assuming historical land 

use changes will continue to be 

followed in response to increased 

agricultural demand associated with our 

biofuel policy. We also invite comment 

on what alternative methodologies and 

data are available, if any, to better link 

the impacts of biofuels to land use 

change. To the extent additional 

information or data may be available for 

certain countries such as the example of 

Brazil, we also ask how this countryspecific data and similar information 

might best be integrated with the 

modeling results otherwise available. 

Furthermore, to the extent different 

government policies can shift land use 

patterns (e.g., through regulations, 

financial supports), these weighted 

averages could change in the future. We 

request comment on whether these 

government policies and regulations 

should be incorporated into the future 

land use change calculations and the 

best methodology for taking into 

account these changes. 

The Winrock data and analyses 

present an aggregate picture of land use 

changes; they cannot predict the nature 

of the land use change that will result 

due to an additional acre of corn 

planted in a country versus an 

additional acre of sugarcane or 

soybeans. In reality, sugarcane may be 

more suitable for planting in different 

regions with different soil types 

compared to corn or soybeans. However, 

because we are using weighted averages 

to characterize the type of land that is 

converted to crop acres, all additional 

crop acres in a particular country are 

treated identically. 

Winrock also provides information on 

land conversions between other 

categories (e.g., forest to savanna). For 

one set of GHG analyses, we assumed 

that land taken out of actively managed 

use 279 (e.g., pasture used for livestock 

production) would have to be replaced 

with new pasture acreage, thereby 

capturing some of the domino effect 

associated with converting previously 

productive land into cropland. 

Therefore, in addition to land 

conversion shown in Table VI.B.5–1, we 

also include land conversion to replace 

some of the grassland and savanna that 

is used as pasture. An alternative 

approach would be to assume that no 

additional land is necessary, since there 

is a significant amount of pastureland 

that could be used more intensively for 

grazing purposes. For example, as noted 

above, in Brazil almost all of the direct 

land conversion associated with 

expanding sugarcane production is 

coming out of existing pasture land, in 

some cases, depleted, low value pasture 

land, that may have relatively low levels 

of stored carbon compared to other land. 

Also in Brazil there is a trend toward 

more intensive use of existing pasture 

land by grazing higher numbers of cattle 

per unit of pasture, decreasing the need 

to replace pasture converted to 

cropland. This more intensive use of 

pasture is encouraged by two factors: 

improved grasses which can sustain 

more intensive grazing and lack of 

transportation infrastructure which 

tends to constrain geographic expansion 

of pasture lands. However, we also note 

that depleted cropland in Brazil might 

also be suitable for other crop 

production. To extend sugarcane limits 

to production of these other crops on 

this land, the indirect effect could be 

that these crops move into other areas 

of Brazil and resulting in increased 

emissions due to land use change. We 

invite comment on alternative 

methodologies for predicting land use 

changes in particular in other countries. 

Some alternative methodologies are 

described in more detail in Chapter 2 of 

the DRIA. 

The FAPRI model results have been 

used in peer reviewed literature in 

conjunction with satellite data to assess 

land use changes 280 and we also believe 

it is an appropriate method for 

projecting biofuel induced land use 

changes. However, we recognize the 

uncertainty associated with this 

approach and, in addition to seeking 

public comment, we plan to conduct an 

expert peer review of the data and 

methods used, including the 

appropriateness of using historic 

satellite data to project future land use 

changes. 

iv. What Are the GHG Emissions 

Associated With Different Types of 

Land Conversion? 

Our estimates of domestic land use 

change GHG emissions are based on 

outputs of the FASOM model. As we are 

just using the agricultural portion of the 

FASOM model for this analysis the land 

use change GHG emissions are limited 

to changes in land use for existing crop 

and pasture land. Some of that crop 

land could currently be fallow and some 

of the pasture land could currently be 

unused. However, no new crop or 

pasture land (beyond some 

Conservation Reserve Program (CRP) 

land due to legislative changes in the 

program) is added compared to current 

levels. Thus FASOM only models shifts 

in the use of this land. 

Changes in the agricultural sector due 

to increased corn used for ethanol have 

impacts on land use change in a number 

of ways. FASOM explicitly models 

change in soil carbon from increased 

crop production acres and from 

different types of crop production. 

FASOM also models changes in soil 

carbon from converting non crop land 

into crop production. Land converted to 

crop land could include pasture land. 

As recommended by USDA, we are 

assuming that 32 million acres of CRP 

land will remain in that program even 

if crop prices increase and thus increase 

land values. This assumption is 

consistent with the 2008 Farm Bill, 

which limits CRP acres to 32 million. A 

sensitivity analysis on this assumption 

is included in Chapter 5 of the DRIA. 

For the international impacts, we 

used the 2006 IPCC Agriculture, 

Forestry, and Other Land Use (AFOLU) 

Guidelines 281 and the Winrock 

provided GHG emissions factors for 

each country based on the weighted 

average type of land converted. GHG 

emissions estimates were based on 

immediate releases (e.g., changes in 

biomass carbon stocks, soil carbon 

stocks, and non-CO2 emissions 

assuming the land is cleared with fire) 

and foregone forest sequestration (the 

future growth in vegetation and soil 

carbon). Additional details on these 

calculations are included in Chapter 2 

of the DRIA. For the emissions factors 

presented, we assume forests cleared 

would have continued to sequester 

carbon for another 80 years, based on 

the amount of time it takes for forests to 

reach a general equilibrium stage. We 

request comment on whether it is 

appropriate to include foregone 

sequestration in the GHG emissions 

estimates. Carbon soil calculations 282

take into account the annual changes in 

carbon content in the top 30 centimeters 

of soil over the first 20 years, based on 

IPCC recommendations.283 We also 

request comment on whether soil 

carbon calculations should be based on 

the top 30 centimeters of soil. These 

emission factors do not include credits 

for harvested wood products, based on 

the expectation that they would have a 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25033 

284https://www.gtap.agecon.purdue.edu. 

285See Hertel, Thomas, Steven Rose, Richard Tol 

(eds.), (in press). Economic Analysis of Land Use in 

Global Climate Change Policy, Routledge 

Publishing. 

286 Land Use Change Carbon Emissions due to US 

Ethanol Production, Wallace E. Tyner, Farzad 

Taheripour, Uris Baldos, January 2009. Available at 

http://www.agecon.purdue.edu/papers/biofuels/ 

Argonne-GTAP_Revision%204a.pdf. 

very small impact on our estimates of 

land use change emissions. However, 

we intend to analyze the impact of 

wood product credits for the final rule. 

We invite comment on whether it is 

appropriate to include wood product 

credits in the GHG emissions estimates. 

GHG emissions associated with land 

use changes vary significantly based on 

the type of land and the geographic 

region. For example, the GHG emissions 

associated with converting an acre of 

grassland to cropland in China are lower 

than the emissions associated with 

converting an acre of shrubland to 

cropland in China. Similarly, the GHG 

emissions associated with converting an 

acre of forest to cropland in Malaysia 

are larger than the emissions associated 

with converting an acre of forest in 

Nigeria to cropland. Where country 

specific emission factors were not 

available in time for the proposal, we 

used world average. For the proposal, 

we focused on the countries with the 

largest projected changes in crop 

acreage. The Winrock data currently 

covers 63% of total land use change 

acres associated with corn ethanol, 53% 

of the acres associated with biodiesel, 

57% of the acres associated with 

switchgrass, and 87% of the acres 

associated sugarcane ethanol. We will 

continue to add additional countries for 

our analysis for the final rule. Two 

changes that may impact these results 

for the final rule include the addition of 

perennial crops and the conversion on 

land with peat soils. We request 

comment on our calculation of emission 

factors due to land use change; 

improved data and assumptions are 

specifically requested. Additionally, we 

plan to have the calculation of these 

emissions factors reviewed by experts in 

this field. Details on the Winrock 

estimates are included in the DRIA 

Chapter 2. 

GTAP Approach: 

GTAP is an economy-wide general 

equilibrium model that was originally 

developed for addressing agricultural 

trade issues among countries. The 

databases and versions of the model are 

widely used internationally.284 Since its 

inception in 1993, GTAP has rapidly 

become a common ‘‘language’’ for many 

of those conducting global economic 

analysis. For example, the WTO and the 

World Bank co-sponsored two 

conferences on the so-called 

Millennium Round of Multilateral Trade 

talks in Geneva. Here, virtually all of the 

quantitative, global economic analyses 

were based on the GTAP framework. 

Over the past few years, a version of the 

model was developed to explicitly 

model global competition among 

different land types (e.g., forest, 

agricultural land, pasture) and different 

qualities of land based on the relative 

value of the alternative land-uses. More 

recently, it was modified to include 

biofuel substitutes for gasoline and 

diesel. In simulating land use changes 

due to biofuels production, GTAP 

explicitly models land-use conversion 

decisions, as well as land management 

intensification. For example, it allows 

for price-induced yield changes (e.g., 

farmers can reallocate inputs to increase 

yields when commodity prices are high) 

and considers the marginal productivity 

of additional land (e.g., expansion of 

crop land onto lower quality land as a 

result of the increased use of biofuels). 

Most importantly, in contrast to other 

models, GTAP is designed with the 

framework of predicting the amount and 

types of land needed in a region to meet 

demands for both food and fuel 

production. The GTAP framework also 

allows predictions to be made about the 

types of land available in the region to 

meet the needed demands, since it 

explicitly represents different land types 

within the model. 

The global modeling of land-use 

competition and land management 

decisions is relatively new, and 

evolving.285 GTAP does not yet contain 

cellulosic feedstocks in the model. In 

addition, GTAP does not currently 

contain unmanaged land, which could 

be a major factor driving current GTAP 

land use projections and is a significant 

potential source of GHG emissions. We 

expect to update GTAP with cellulosic 

feedstocks and unmanaged land in time 

for the final rule. 

Our proposal is therefore based on the 

FAPRI/Winrock estimates. There are 

advantages and disadvantages 

associated with any model choice and 

we have chosen the FAPRI/Winrock 

combination as the best approach 

available for preparing the proposal. 

Although we have not relied on the 

current version of GTAP for the 

principal analyses in this proposal, 

others have used versions of the current 

model to assess land use changes which 

could result from expanded biofuel 

demand. The California Air Resources 

Board as part of the analysis for their 

low carbon fuel standard used GTAP to 

model indirect land use change for 

biofuels. More information on their 

program and GTAP analysis can be 

found at http://www.arb.ca.gov/fuels/ 

lcfs/lcfs.htm. Furthermore, researchers 

from Purdue University have released a 

report on work using GTAP to look at 

land use change associated with corn 

ethanol production scenarios.286 This 

work was partially funded by Argonne 

National Lab for possible inclusion in 

the GREET model. We anticipate 

additional refinements will be made to 

the GTAP model between the proposal 

and final rule and we will include this 

information and results in the docket as 

they become available. We invite 

comments in this NPRM on the use of 

the GTAP model in helping to establish 

the GHG emissions estimates for the 

final rule. 

v. Assessing GHG Emissions Impacts 

Over Time and Potential Application of 

a GHG Discount Rate 

When comparing the lifecycle GHG 

emissions associated with biofuels to 

those associated with gasoline or diesel 

emissions, it is critical to take into 

consideration the time profile associated 

with each fuel’s GHG emissions stream. 

With gasoline, a majority of the lifecycle 

GHG emissions associated with 

extraction, conversion, and combustion 

are likely to be released over a short 

period of time (i.e., annually) as crude 

oil is converted into gasoline or diesel 

fuel which quickly pass to market. This 

means that the lifecycle GHG emissions 

of a gallon of gasoline produced one 

year are unlikely to vary much from the 

lifecycle GHG emissions of a similar 

gallon of gasoline produced in a 

subsequent year. 

In contrast, the lifecycle GHG 

emissions from the production of a 

typical biofuel may continue to occur 

over a long period of time. As with 

petroleum based fuels, renewable fuel 

lifecycle GHG emissions are associated 

with the conversion and combustion of 

biofuels in every year they are 

produced. In addition, GHG emissions 

could be released through time if new 

acres are needed to produce corn, 

soybeans or other crops as a 

replacement for crops that are directly 

used for biofuel production or displaced 

due to biofuels production. The GHG 

emissions associated with converting 

land into crop production would 

accumulate over time with the largest 

release occurring in the first few years 

due to clearing with fire or biomass 

decay. After the land is converted, 

moderate amounts of soil carbon would 

continue to be released for 

25034 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

287Following Section 5.3.3.4 of the IPCC AFOLU 

guidelines, the total difference in soil carbon stocks 

before and after conversion was averaged over 20 

years. 

288Table 4.9 from the 2006 GL AFOLU was used 

to estimate the lost C sequestration of forests that 

were converted to another land use. 

289See Greenhouse Gas Mitigation Potential in 

U.S. Forestry and Agriculture, EPA Document 430– 

R–05–006 for a discussion of the time required for 

forests to reach carbon saturation. 

290Luyassert, S et al., 2008. Old-growth forests as 

global carbon sinks. Nature 455: 213–215. Link: 

http://www.nature.com/nature/journal/v455/n7210/ 

abs/nature07276.html. 

approximately 20 years.287 Furthermore, 

there would be foregone sequestration 

associated with forest clearing as this 

forest would have continued to 

sequester carbon had it not been cleared 

for approximately 80 years. 

Therefore, we have included an 

analysis which considers GHG 

emissions from land use change that 

may continue for up to 80 years, based 

on our estimate of the average length of 

foregone sequestration after a forest is 

cleared. Annual foregone sequestration 

rates were estimated by ecological 

region using growth rates for forests 

greater then 20 years old from the 2006 

IPCC guidelines for Agriculture, 

Forestry and Other Land Use.288 Studies 

have estimated that new forests grow for 

90 years to over 120 years.289 More 

recent estimates suggest that old growth 

forests accumulate carbon for up to 800 

years.290 The foregone sequestration 

methods used in this proposal are 

within the range supported by the 

scientific literature and the 2006 IPCC 

guidelines. Details of the foregone 

sequestration estimates are included in 

DRIA Chapter 2. We seek comment on 

our estimate of the average length of 

annual foregone forest sequestration for 

consideration in biofuel lifecycle GHG 

analysis. 

Figure VI.B.5–1 shows how lifecycle 

GHG emissions vary over time for a 

natural gas fired dry mill corn ethanol 

plant assuming that all land use change 

occurs in 2022. While biomass 

feedstocks grown each year on new 

cropland can be converted to biofuels 

that offer an annual GHG benefit relative 

to the petroleum product they replace, 

these benefits may be small compared to 

the upfront release of GHG emissions 

from land use change. Depending on the 

specific biofuel in question, it can take 

many years for the benefits of the 

biofuel to make up for the large initial 

releases of carbon that result from land 

conversion (e.g., the payback period). As 

shown in Figure VI.B.5–1, the payback 

period for a natural gas-fired dry mill 

corn ethanol plant which begins 

operation in 2022 would be 

approximately 33 years. We present a 

similar payback period calculation for 

the full range of biofuels analyzed in 

Section VI.C. 

As required by EISA, our analysis 

must demonstrate whether biofuels 

reduce GHG emissions by the required 

percentage relative to the 2005 

petroleum baseline. A payback period 

alone cannot answer that question. 

Since the payback period alone is not 

sufficient for our analysis, we have 

considered accounting methods for 

capturing the full stream of emissions 

and benefits over time. There are at least 

two necessary criteria for the accounting 

methods we have considered. First, they 

must provide an estimate of renewable 

fuel lifecycle GHG emissions that is 

consistent over time. Otherwise, for 

example, all of the upfront emissions 

due to land clearing would be assigned 

to corn ethanol produced in the first 

year, and none of those emissions to 

corn ethanol produced the following 

years even though this land use change 

is central to the production over these 

following years. Second, the accounting 

method must also provide a common 

metric that allows for a direct 

comparison of biofuels to gasoline or 


EP26MY09.008</GPH>
Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25035 

291Luyassert, S et al., 2008. Old-growth forests as 

global carbon sinks. Nature 455: 213–215. Link: 

http://www.nature.com/nature/journal/v455/n7210/ 

abs/nature07276.html. 

292Searchinger et al., 2008. 

293M. Delucchi, ‘‘A multi-country analysis of 

lifecycle emissions from transportation fuels and 

motor vehicles’’ (UCD–ITS–RR–05–10, University 

of California at Davis, Davis, CA 2005). See also 

http://www.its.ucdavis.edu/people/faculty/ 

delucchi/. 

diesel. When accounting for the time 

profile of lifecycle GHG emissions, the 

two most important assumptions in the 

determination of whether a biofuel 

meets the specified emissions reduction 

thresholds include: (1) The time period 

considered and (2) the discount rate 

(which could be zero) applied to future 

emissions streams. 

Time Periods Considered 

The illustration of the payback period 

in Figure VI.B.5–1 demonstrates the 

importance of the time period over 

which to consider both the lifecycle 

GHG emissions increases associated 

with the production of a biofuel as well 

as the benefits from using the biofuel. 

As mentioned above, based on our 

lifecycle GHG analysis for this proposed 

rule we estimate that the payback period 

for corn ethanol produced in a natural 

gas-fired dry mill is approximately 33 

years. In this case, if we measure GHG 

impacts over a time period of less than 

33 years we will determine that the total 

corn ethanol produced over this time 

period increases lifecycle GHG 

emissions. Conversely, total corn 

ethanol production will reduce net 

lifecycle GHG emissions if we look 

beyond 33 years, with net emissions 

reductions increasing the further into 

the future we extend our analysis. To 

inform our decision of which time 

period for analysis is most appropriate, 

we must consider a number of factors 

including but not limited to the length 

of time over which we expect a 

particular biofuel to be produced, the 

time over which biofuel production 

continues to impact GHG emissions into 

the future, the importance of achieving 

near-term GHG emissions reductions, 

and the increasing uncertainty of 

projecting GHG emissions impacts into 

the future. Based on these 

considerations, our discussion of 

lifecycle analyses prepared for this 

proposed rule focuses on time periods 

of 100 years and 30 years. 

There are advantages and 

disadvantages to using the 100 and 30 

year time frames to represent both 

emissions impacts as well as emissions 

benefits of use of biofuels over time. 

There are several principal reasons for 

using the 100 year time frame. First, 

greenhouse gases are chemically stable 

compounds and persist in the 

atmosphere over long time scales that 

span two or more generations. Second, 

the 100 year time frame captures the 

emissions associated with land use 

change that may continue for a long 

period of time after biofuel-induced 

land conversion first takes place.291 For 

example, physical changes in carbon 

stocks on unmanaged lands may not 

slow until after 100 years, and optimal 

forest rotation ages can influence 

greenhouse gas emissions for 100 years 

on managed lands. Similarly, a 100 year 

time frame would allow estimating the 

future changes in the land should the 

need for these changes due to biofuel 

production cease. For example, as 

discussed in more detail below, if 

production of a biofuel ended, then the 

land use impacts associated with that 

biofuel would also tend to go away in 

a process known as land use reversion. 

A longer time frame would allow 

assessment of the impacts of that land 

use reversion. 

For a number of reasons we believe 

that biofuel production could continue 

for a long time into the future. As 

biofuel technologies advance and 

production costs are decreased, it is 

likely that renewable fuels will become 

increasingly competitive with 

petroleum-based fuels. Another reason 

for expecting long term biofuel 

production is that, unlike a specific 

facility that has an expected lifetime, 

the RFS program does not have a 

specified expiration date. The 

expectation that renewable fuel 

production will continue for a long time 

provides justification for using a longer 

time frame for analysis, such as 100 

years. Another reason for considering an 

inter-generational time period such as 

100 years for lifecycle GHG analysis is 

that climate change is a long-term 

environmental problem that may require 

GHG emissions reductions for many 

decades. 

The 100 year time frame also has 

drawbacks. A general concern with 

projecting impacts over a very long time 

period is that uncertainty increases the 

further the analysis is extended into the 

future. For example, a 100 year analysis 

presumes that production of a particular 

biofuel will continue for at least 100 

years. Although we expect renewable 

fuel production as a whole to continue 

for a long time, it is possible that due 

to changing market conditions or other 

factors, the use of first generation 

biofuels (e.g., corn ethanol) could see a 

decline in use over a shorter period of 

time. 

For this proposal, we are also showing 

the results of analyzing both GHG 

emissions impacts of producing a 

biofuel as well as benefits from using 

the biofuel over 30 years, a time frame 

which has been used in the literature to 

estimate the greenhouse gas impacts of 

biofuels.292 293 Since a time period such 

as 30 years would truncate the potential 

GHG benefits that accumulate over time, 

this second option would reduce the 

GHG benefits of biofuels relative to 

gasoline or diesel compared to assuming 

a longer time frame for biofuel 

production such as 100 years. 

One advantage of using a shorter time 

period is that it is more ‘‘conservative’’ 

from a climate change policy 

perspective. In general, the further out 

into the future an analysis projects, the 

more uncertainty is introduced into the 

results. For example, with a longer time 

period for analysis, it is more likely that 

significant changes in market factors or 

policies will change the incentives for 

producing biofuels. If a biofuel only has 

greenhouse benefits when considered in 

an extended future time frame, it is not 

clear that these benefits will be realized 

due to the inherent uncertainty of the 

future. Also, potential irreversible 

climate change impacts or future actions 

in other sectors of the economy, such as 

reductions from stationary sources, 

could influence the relative importance 

of renewable fuel GHG impacts. The 

timing and severity of these potential 

irreversible climate change impacts are 

clearly uncertain as is the degree to 

which near-term lifecycle emissions 

related to biofuel production influences 

these climate change impacts. Given 

these uncertainties, it may be 

appropriate to limit our analysis horizon 

to a much shorter time period such as 

30 years. 

Several disadvantages are also 

associated with choosing the 30 year 

time frame to represent both emissions 

impacts as well as emissions benefits. 

One key disadvantage is that it ignores 

the potential sources of GHG emissions 

impacts of producing biofuel after 30 

years such as foregone sequestration 

from forests that may have been 

removed which could have continuing 

impacts even after production of a 

biofuel has ended. Thus, it doesn’t 

account for the full land use emissions 

‘‘signature’’ of biofuels. In addition, 

even if second generation fuels start to 

dominate new construction, building a 

first generation fuel production facility 

such as a corn ethanol refinery 

represents a significant capital 

investment. Once the facility is built 

and financed, it may continue 

25036 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

producing biofuel as long as it is 

covering its operating costs. This 

suggests that, once a plant is built, if the 

variable cost of corn ethanol production 

is less than the cost to produce gasoline, 

then corn ethanol production at that 

facility may continue. This economic 

advantage may contribute to the 

longevity of first generation biofuel 

production and usage far into the future. 

An appropriate time frame for 

analysis could also be different for 

different biofuels. While we could 

assume that corn ethanol would be 

phased out after a shorter time period 

such as 30 years, it might be more 

appropriate to use a longer time period 

over which to analyze the benefits of 

other advanced biofuels such as 

cellulosic biofuels. It could be 

reasonably assumed that cellulosic 

biofuels will be produced for more than 

30 years, perhaps for 100 years or 

longer. However, even if cellulosic 

biofuels are expected to be produced for 

100 years or longer, a shorter time 

period, such as 30 years, may still be the 

most relevant period over which to 

assess GHG emissions, given the 

importance of near-term emissions 

reductions and the increasing 

uncertainty of future events. We 

specifically seek comments on the 100 

year and 30 year time frames discussed 

in this proposal. We also seek general 

comments on the most appropriate time 

periods for analysis of biofuels, and 

whether we should use different time 

periods for different types of renewable 

fuels. 

Another way to look at the time 

period issue, which we have not 

specifically analyzed for this proposed 

rule, would separate the time period 

into two parts. The first part would 

consider how long we expect 

production of a particular biofuel to 

continue into the future. We refer to this 

concept, which is similar to the project 

lifetime often considered in traditional 

cost benefit analysis, as the ‘‘project’’ 

time horizon. The second part would 

address the length over which to 

account for the changes in GHG 

emissions due to land use changes 

which result from biofuel production. 

We call this the ‘‘impact’’ time horizon. 

Our analysis for this proposed rule 

has not considered a scenario where the 

project time horizon is shorter than 

impact time horizon. However, we are 

considering this option for the final 

rule. For example, we could look at a 

scenario where corn ethanol production 

continues for 30 years and land use 

related GHG emissions are estimated for 

100 years. Specifically, we are 

considering whether to use 30 years 

after 2015 (as an approximation of when 

ethanol production from corn starch 

reaches 15 billion gallons) as a 

reasonable estimate of when corn will 

no longer be used for ethanol 

production due to advances in other 

biofuels and the competing demand to 

use corn for food rather than biofuel 

feedstock. We specifically ask whether a 

30 year estimate of continued corn 

starch ethanol production (i.e., through 

2045) is a reasonable estimate for 

assessing the stream of GHG benefits 

from corn ethanol use while 100 years 

would be appropriate for assessing 

impacts of the land use change. Under 

such an assumption a 100 time horizon 

would capture the longer term emission 

impacts of corn ethanol production 

(including indirect land use impacts) 

while the benefits from 31 through 100 

years would be zero since corn ethanol 

would be modeled as no longer in use. 

In that scenario, we would have to 

consider the lifecycle GHG impacts after 

the production of corn ethanol ends. 

This would include the issue of land 

reversion, or what happens to the land 

used to produce a biofuel feedstock after 

its use for biofuel production has 

ceased. A full accounting of land 

reversion would involve economic 

modeling to determine how long we 

expect production of a particular biofuel 

to last, and to determine the land use 

changes after that biofuel production 

ends. Ideally this modeling would 

extend well beyond 2022 to the point 

where land reversion is complete, and it 

would include projections for global 

crop yield improvements, population 

trends, food demand, and other key 

factors. For this proposal, we have not 

projected the GHG emissions associated 

with land reversion, but we plan to 

consider land reversion in our final rule 

analysis and we seek comments on 

methodologies and approaches for doing 

this. We also seek comment on the 

related issue of how best to estimate 

how long each type of biofuel is most 

likely to continue to be produced, and 

whether production of these biofuels is 

likely to end abruptly or phase out 

gradually. 

Agricultural and economic models 

that look beyond 2022 would not only 

help to estimate the impacts of land 

reversion after biofuel production ends, 

they would also help to project how 

evolving agricultural conditions could 

influence the lifecycle GHG emissions 

of biofuels beyond 2022. For example, 

corn yields per acre are expected to 

continue increasing after 2022; this 

increase in yields per acre will decrease 

the amount of land required to produce 

a bushel of corn. At higher yields, fewer 

acres are required to grow the corn used 

for the 15 billion gallons of corn starch 

ethanol modeled for the rule. The 

indirect impacts of maintaining 15 

billion gallons of corn ethanol 

production would similarly be reduced. 

EPA intends to more carefully model 

these transitions in particular to better 

account for future land use impacts and 

we invite comments on methodology, 

sources of data, factors that should be 

considered in assessing whether and 

when a particular biofuel such as 

ethanol from corn starch, for example, 

will no longer be produced and 

recommendations on how to improve on 

our assessment of the likely stream of 

GHG emissions after 2022 that will 

result from the EISA mandates. 

A complicating consideration in this 

analysis arises in determining future use 

of the land (post-biofuel production) is 

the fact that perhaps significant land use 

change occurred as a result of biofuel 

production and that land is now more 

easily suited for alternative uses 

compared to its pre-biofuel state. For 

example, the demand created by biofuel 

production may have justified clearing 

forested lands and turning them into 

productive cropland. Even if the need 

for the land to produce crops in 

response to biofuel demand ceases 

when the biofuel production ends, the 

land will still be in an altered form 

making it, for example, more 

economically available for other crop 

production than when it had been 

forested. How this land is subsequently 

used can affect its impact on GHG 

emissions. If it is used for intensive crop 

production, the land will have a much 

different carbon sequestration profile, 

for example, than if it returned to its 

pre-biofuel forested state. EPA asks for 

suggestions on how to best treat these 

lingering effects of land use change 

when attributing the effects of biofuel 

demand to uses of land even after 

biofuel production ends. 

For the determination of whether 

biofuels meet the GHG emissions 

reduction required by EISA, we present 

the results for a range of time periods, 

including both 100 years and 30 years 

in Section VI.C and specifically invite 

comment on whether use of a 100 year 

time frame, a 30 year time frame, or 

some other time frame, would be most 

appropriate. 

In addition to this general issue of the 

appropriate time frames for analysis, 

several more specific issues exist. Since 

it would be likely that corn starch 

ethanol production will phase out 

gradually rather than stopping all of a 

sudden in 2045, we also are evaluating 

options for estimating the phase out of 

corn starch ethanol production. One 

simplifying assumption would have 

corn ethanol production phase out 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25037 

294Herzog et al. 2003 (See http:// 

sequestration.mit.edu/pdf/climatic_change.pdf), 

Richards 1997, Stavins and Richards 2005 (See 

http://www.pewclimate.org/docUploads/ 

Sequest_Final.pdf). 

295Sunstein and Rowell, 2007, On Discounting 

Regulatory Benefits: Risk, Money, and 

Intergenerational Equity, Chicago Law Review. 

296Ramanathan and Feng, 2008. On avoiding 

dangerous anthropogenic interference with the 

climate system: Formidable challenges ahead. 

Proceedings of the National Academy of Sciences 

105:143245–14250. 

297Technical Support Document on Benefits of 

Reducing GHG Emissions, U.S. Environmental 

Protection Agency, June 12, 2008, 

www.regulations.gov (search phrase ‘‘Technical 

Continued 

linearly between 2022 and 2045 as 

production of other biofuels such as 

cellulosic biofuels continue to expand. 

Comments are requested on the option 

of linearly phasing out corn ethanol 

production from 2022 through 2045 and 

other approaches for estimating this 

transition in corn ethanol production. 

Finally, its not only corn starch ethanol 

that might be replaced in future years. 

For example, the use of soy oil for 

biodiesel fuel production might be 

replaced by other non-food oils such as 

oil from algae. Comments are requested 

on whether other biofuels will similarly 

phase out of use and therefore the land 

use change impacts need to be similarly 

considered. 

In addition to seeking comments on 

all of the issues related to the time 

periods for lifecycle analysis, EPA plans 

to convene a peer review of the range of 

time periods considered in this 

proposed rule. This peer review will 

also seek expert feedback on all of the 

issues raised above in this section, 

including how to determine the most 

appropriate time periods for 

consideration in the final rule. 

Discounting of Lifecycle GHG Emissions 

Economic theory suggests that in 

general consumers have a time 

preference for benefits received today 

versus receiving them in the future. 

Therefore, future benefits are often 

valued at a discounted rate. Although 

discount rates are most often applied to 

the monetary valuation of future versus 

present benefits, a discounting approach 

can also be used to compare physical 

quantities (i.e., total GHG emissions per 

gallon of fuel used). 

The concept of weighting physical 

units accruing at different times has 

been used in the environmental and 

resource economics literature,294 and is 

analogous to valuing the monetary cost 

and benefits of a policy, only that in this 

case the metric that we ‘value’ is the 

reduction in GHG emissions. 295 An 

important part of the economic theory of 

time is the idea that benefits expected 

to accrue in the long term are less 

certain than benefits in the near term. 

This is true in the case of GHG 

emissions changes from biofuel 

production which are dependent upon 

how long biofuel production will 

continue, how technologies will 

develop over time, and other factors. 

Another reason to give more weight to 

near-term emissions changes is that the 

risks associated with climate change in 

the future include the possibility of 

extreme climate change and threshold 

impacts (e.g., species and ecosystem 

thresholds, catastrophic events). 

Increased GHG emissions in the nearterm may be more important in terms of 

physical damage to the world’s 

environment. Some scientists, for 

example, believe that effects on factors 

such as arctic summer ice, HimalayanTibetan Glaciers, and the Greenland ice 

sheet are more likely to be effected by 

near-term GHG emissions, causing nonlinearities in the effects attributable to 

GHG emissions.296 Long-term GHG 

reductions may be too late to mitigate 

these irreversible impacts, providing 

further justification for discounting 

GHG emissions changes that are 

expected in the distant future. Under 

this perspective, it would be appropriate 

to discount the physical quantities of 

future emissions, and especially in a 

long term analysis of lifecycle GHG 

emissions. Thus in our analysis with a 

100 year time frame, or impact horizon, 

we discount the value of future GHG 

emissions changes. 

Despite the rationale for discounting 

future GHG emissions changes 

discussed above, there are reasons to be 

cautious about the application of 

discounting in lifecycle GHG analysis. 

One argument is that it may only be 

appropriate to discount monetized 

values. Our lifecycle analysis estimates 

GHG emission impacts, not their 

monetary value, and under this 

argument emissions should not be 

directly discounted. Rather, the physical 

GHG emissions should be converted 

into monetary impacts, where these 

monetary impacts are also a function of 

climate science. The resulting climate 

impacts would then have to be 

translated into monetary values. This 

presents significant challenges for 

lifecycle GHG analysis because it is 

difficult to translate dynamic GHG 

emissions into a single estimate of 

physical impacts, much less a single 

estimate of monetized impacts. This is 

the case for a number of reasons, 

including the complex physical systems 

associated with climate change (e.g., the 

relationship between atmospheric 

degradation rates with atmospheric 

carbon stocks) that may create nonconstant marginal damages from GHG 

emissions over time. Furthermore, 

converting lifecycle GHG emissions into 

monetized impacts may be inconsistent 

with the EISA definition of lifecycle 

GHG emissions provided above in 

Section VI.A.1, which stipulates that 

lifecycle GHG emissions are the 

‘‘aggregate quantity of greenhouse gas 

emissions * * * where the mass values 

for all greenhouse gases are adjusted to 

account for their relative global 

warming potential.’’ 

Another argument against discounting 

GHG emissions changes is the concept 

of inter-generational equity, which 

argues that benefits or damages affecting 

future generations merit just as much 

weight as impacts felt by current 

generations. It is argued that this would 

invalidate the practice of discounting 

emissions impacts that could affect 

future generations. 

Finally, earlier in this section we 

discussed the possible ranges of time 

frames for analyzing the GHG emissions 

impacts. For shorter time frames such as 

30 years, there would be less 

uncertainty in the emissions stream so 

the benefit of discounting to address 

uncertainty is also lessoned. 

Comments are requested on the 

concept of discounting a stream of GHG 

emissions for the purpose of estimating 

lifecycle GHG emissions from 

transportation fuels as specified in 

EISA. 

Appropriate Level of Discount Rate 

As described in more detail in Section 

IX on GHG emission reduction benefits, 

GHG emissions have primarily 

consumption effects and intergenerational impacts, as changes in 

GHG emissions today will continue to 

have impacts on climate change for 

decades to centuries. If a discount rate 

is applied to future GHG emissions, an 

appropriate discount rate should be 

based on a consumption-based discount 

rate given that monetized climate 

change impacts are primarily 

consumption effects (i.e., impacts on 

household purchases of goods and 

services). A consumption-based 

discount rate reflects the implied 

tradeoffs between consumption today 

and in the future. Discount rates of 3% 

or less are considered appropriate for 

discounting climate change impacts, 

since they reflect the long run 

uncertainty in economic growth and 

interest rates and the risk of high impact 

climate damages that could reduce 

economic growth.297

25038 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

Support Document on Benefits of Reducing GHG 

Emissions’’). 

298Searchinger et al., 2008. 

299Tol, 2005. 

300Newell and Pizer, 2003. 

301OMB Circular A–4, 2003 provides a range of 

1–3% for consumption based discount rates. 

302EPA Guidelines for Preparing Economic 

Analyses, 2000. 

303Tol (2005, 2007). 

304Newell and Pizer, 2003, Weitzman (1999, 

2001), Nordhaus (2008), Guo et al., (2006), Saez, 

C.A. and J.C. Requena, ‘‘Reconciling sustainability 

and discounting in Cost-Benefit Analysis: A 

methodological proposal’’, Ecological Economics, 

2007, vol. 60, issue 4, pages 712–725. 

305See Memo to EPA, Office of Transportation 

and Air Quality from Union of Concerned 

Scientists, Re: Treatment of Time in Life Cycle 

Accounting, February 18, 2009. 306See http://www.ipcc.ch/ipccreports/ 

assessments-reports.htm. 307O’Hare, Plevin, Martin, Jones, Kendal and 

Hopson; ‘‘Proper accounting for time increases 

crop-based biofuel’s greenhouse gas deficit versus 

petroleum’’; Environmental Research Letters, 4 

(2009) 024001. 

When analyzing the GHG emissions 

associated with a 100 year time period, 

we examined a variety of alternative 

discount rates (e.g., 0, 2, 3, 7 percent) to 

show the sensitivity of greenhouse gas 

emissions estimates to the choice of the 

discount rate. A zero discount rate 

estimates GHG emission impacts as if 

each ton of GHG emissions is treated 

equally through time. Previous 

methodologies of lifecycle GHG benefits 

have presented results using a zero 

discount rate.298 However, some of the 

climate change literature supports using 

a higher discount rate, as described in 

Section IX.C. We show the 7% discount 

rate for illustrative purposes; however 

climate change benefit analyses from 

global long-run growth models typically 

use discount rates well under 7% for 

standard analysis.299 High discount 

rates imply very low values for the 

future GHG emission impacts resulting 

from today’s actions on the welfare of 

future generations. Therefore, lower 

discount rates such as 2–3% are 

considered more appropriate for 

discounting long term climate change 

impacts.300

In the analysis for this proposal we 

use a 2% discount rate to assess the 

present value of GHG emissions changes 

which occur over a 100 year time frame. 

This discount rate is consistent with the 

Office of Management and Budget 

(OMB) 301 and EPA 302 guidance and is 

one of the discount rates that has been 

used in the literature to monetize the 

impacts of climate change.303 EPA has 

considered this issue previously, and 

after weighing the pros and cons of 

different values, set forth a guidance 

document recommending using a range 

of consumption based discount rates of 

0.5–3%. OMB and EPA guidance on 

inter-generational discounting suggests 

using a low but positive discount rate if 

there are important inter-generational 

benefits and costs. In selecting a 2% 

discount rate coupled with a 100 year 

emission stream estimate, EPA would be 

recognizing the long term nature of the 

emission impacts of biofuel production, 

the uncertainty in estimating these 

emission impacts and their 

consequences plus the significance of 

nearer term emission changes in 

avoiding future consequences. Other 

options for intergenerational 

discounting have been discussed in the 

economic literature, such as dealing 

with uncertainty by using a nonconstant, declining, or negative discount 

rate.304 Comments could consider how 

discounting appropriately reflects the 

uneven emission of greenhouse gases 

from biofuels over time, the uncertainty 

in predicting emissions in more distant 

futures and the impacts these emissions 

could have on climate change. 

Alternative approaches for intergenerational discounting are described 

in Chapter 5.3 of the DRIA. 

Because we are considering not 

discounting GHG emissions and in 

particular since the justifications for 

discounting physical emissions are not 

as strong for shorter time periods, in 

Section VI.C.2, we also present the GHG 

emissions reductions associated with 

biofuels using a 30 year time period and 

no discount rate. Using a zero percent 

or no discount rate implies that all 

emission releases and uptakes during 

this time period are valued equally. For 

a shorter time period such as thirty 

years, we are relatively certain of the 

emission trends. Furthermore, all of 

these emissions occur in a relatively 

short period of time so their impact on 

climate change and the consequences of 

that climate change could all be 

considered the same regardless of 

whether those emissions occurred early 

or late in this 30-year time period. 

We specifically invite comment on 

our use of a 2% discount rate with a 100 

year time period for analysis of lifecycle 

GHG emissions, and our use of no 

discount rate in our analysis of GHG 

emissions over 30 years. We also invite 

comments on whether using physical 

science metrics such as the actual 

quantities of climate forcing gasses in 

the atmosphere, actual quantities of 

climate forcing gasses in the atmosphere 

weighted by global warming potential 

(GWP), or cumulative radiative forcing 

should be used to evaluate emissions 

over time. Specifically, we seek 

comment on an approach for comparing 

GHG emissions based on the time 

profile of the greenhouse gas emissions 

in the atmosphere, and whether this 

approach would be consistent with the 

legal definition of lifecycle GHG 

emissions in EISA. One such method is 

the Fuel Warming Potential as outlined 

in a memo to the EPA from the Union 

of Concerned Scientists which is 

available on the public docket for this 

rulemaking.305 This approach is based 

on the ratio of the cumulative radiative 

forcing between the biofuel and the 

gasoline case over a specified time 

frame. 

The EISA definition of lifecycle GHG 

emissions stipulates that the mass 

values for all greenhouse gas emissions 

shall be adjusted to account for their 

relative GWP. We are proposing to use 

the standard 100-year GWP’s published 

in the IPCC Second Assessment 

Report.306 307 We invite comment on 

whether it is appropriate to discount 

GWP-weighted emissions and how such 

discounting might appropriately apply 

across the several greenhouse gases. 

Furthermore, if alternative time 

periods for the production of biofuels 

and the GHG impacts of biofuel 

production are considered as discussed 

above, and the choice is made to 

discount GHG emissions, the question 

that arises is: What discount rate or 

combination of discount rates should be 

considered? For example, if ethanol 

production is assumed to occur for 30 

years and the GHG impacts are assumed 

to span across 80–100 years, should a 

single discount rate be applied to the 

emissions stream or alternative discount 

rates based upon the different time 

frames? EPA is taking comment on 

whether and how to apply discounting 

when different time frames between the 

production and long-run GHG impacts 

are utilized to analysis biofuels. 

Specifically, EPA is considering and 

requests comment on the option of 

using either no discount rate or a 3% 

discount rate to assess those emissions 

that occur during the relatively shorter 

time frame for biofuel use which could 

phase out within 30 years as in our corn 

ethanol example and a 2% discount rate 

over the reminder of the 100 years in 

assessing the longer term GHG 

emissions impacts resulting from land 

use changes related to biofuel 

production (including land reversion 

considerations). 

EPA is considering a range of 

discount rates including zero or no 

discounting for reasons as described 

above and requests comments on the 

appropriate discount rate to use when 

assessing the stream of GHG emission 

changes that are likely to result from 

biofuel production and use. Other 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25039 

308Newell and Pizer, 2003, Weitzman (1999, 

2001), Nordhaus (2008), Guo et al., (2006), Saez, 

C.A. and J.C. Requena, ‘‘Reconciling sustainability 

and discounting in Cost-Benefit Analysis: A 

methodological proposal’’, Ecological Economics, 

2007, vol. 60, issue 4, pages 712–725. 

options for intergenerational 

discounting have been discussed in the 

economic literature, such as dealing 

with uncertainty by using a nonconstant, declining, or negative discount 

rate.308 Comments could consider how 

discounting appropriately reflects the 

uneven release of greenhouse gases from 

biofuels over time, the uncertainty in 

predicting emissions in more distant 

futures and the impacts these emissions 

could have on climate change. 

Alternative approaches for intergenerational discounting are described 

in Chapter 5.3 of the DRIA. 

EPA recognizes that the time horizon 

for analysis and the treatment of future 

emissions including the appropriateness 

of applying discount factors are key 

factors in determining biofuel lifecycle 

GHG impacts; therefore, we plan to 

organize an expert peer review of these 

issues before the final rule. 

c. Feedstock Transport 

The GHG impacts of transporting corn 

from the field to the ethanol facility and 

transporting the co-product DGs from 

the ethanol facility to the point of use 

were included in this analysis. The 

GREET default of truck transportation of 

50 miles was used to represent corn 

transportation from farm to plant. 

Transportation assumptions for DGs 

transport were 14% shipped by rail 800 

miles, 2% shipped by barge 520 miles, 

and 86% shipped by truck 50 miles. The 

percent shipped by mode was from data 

provided by USDA and based on 

Association of American Railroads, 

Army Corps of Engineers, Commodity 

Freight Statistics, and industry 

estimates. The distances DGs were 

shipped were based on GREET defaults 

for other commodities shipped by those 

transportation modes. The GHG 

emissions from transport of corn and 

DGs are based on GREET default 

emission factors for each type of vehicle 

including capacity, fuel economy, and 

type of fuel used. Similar detailed 

analyses were conducted for the 

transport of cellulosic biofuel feedstock 

and biomass-based diesel feedstock. 

As part of this rulemaking analysis we 

have conducted a more detailed analysis 

of biofuel production locations and 

transportation distances and modes of 

transport used in the criteria pollutant 

emissions inventory calculations 

described in DRIA Chapter 1.6 and for 

the cost analysis of this rule described 

in DRIA Chapter 4.2. Given the timing 

of when the current analysis was 

completed we were not able to 

incorporate this updated transportation 

information into our lifecycle analysis 

but plan to do that for the final rule. 

Furthermore, the transportation 

modes and distances assumed for corn 

and DGs do not account for the 

secondary or indirect transportation 

impacts. For example, decreases in 

exports might reduce overall domestic 

agricultural commodity transport and 

emissions but might increase 

transportation of commodities 

internationally. We plan to consider 

these secondary transportation impacts 

in our final rule analysis. 

d. Processing 

The GHG emissions estimates 

associated with the processing of 

renewable fuels is dependent on a 

number of assumptions and varies 

significantly based on a number of key 

variables. The ethanol yield impacts the 

total amount of corn used and 

associated agricultural sector GHG 

emissions. The amount of DGs and other 

co-products produced will also impact 

the agricultural sector emissions in 

terms of being used as a feed 

replacement. Finally the energy used by 

the ethanol plant will result in GHG 

emissions, both from producing the fuel 

used and through direct combustion 

emissions. 

As mentioned above, in traditional 

lifecycle analyses, the energy consumed 

and emissions generated by a renewable 

fuel plant must be allocated not only to 

the renewable fuel, but also to each of 

the by-products. For corn ethanol 

production, our analysis avoids the 

need to allocate by accounting for the 

DGs and other co-products directly in 

the FASOM and FAPRI agricultural 

sector modeling described above. DGs 

are considered a partial replacement for 

corn and other animal feed and thus 

reduce the need to make up for the corn 

production that went into ethanol 

production. Since FASOM takes the 

benefits from the production and use of 

DGs into account (e.g., displacing the 

need to grow additional crops for feed 

and therefore reducing GHG emissions 

in the agricultural sector), no further 

allocation was needed at the ethanol 

plant and all plant emissions are 

accounted for here. 

In terms of the energy used at 

renewable fuel facilities, there is a lot of 

variation between plants based on the 

process type (e.g., wet vs. dry milling) 

and the type of fuel used (e.g., coal vs. 

natural gas). There can also be variation 

between the same type of plants using 

the same fuel source based on the age 

of the plant and types of processes 

included, etc. For our analysis we 

considered different pathways for corn 

ethanol production. Our focus was to 

differentiate between facilities based on 

the key differences between plants, 

namely the type of plant and the type 

of fuel used. One other key difference 

we modeled between plants was the 

treatment of the co-products DGs. One 

of the main energy drivers of ethanol 

production is drying of the DGs. Plants 

that are co-located with feedlots have 

the ability to provide the co-product 

without drying. This has a big enough 

impact on overall results that we 

defined a specific category for wet vs. 

dry co-product. One additional factor 

that appears to have a significant impact 

on GHG emissions is corn oil 

fractionation from DGs. Therefore, this 

category is also broken out as a separate 

category in the following section. See 

DRIA Chapter 1.4 for a discussion of 

corn oil fractionation. 

Furthermore, as our analysis was 

based on a future timeframe, we 

modeled future plant energy use to 

represent plants that would be built to 

meet requirements of increased ethanol 

production, as opposed to current or 

historic data on energy used in ethanol 

production. The energy use at dry mill 

plants was based on ASPEN models 

developed by USDA and updated to 

reflect changes in technology out to 

2022 as described in DRIA Chapter 4.1. 

The GHG emissions from renewable 

fuel production are calculated by 

multiplying the Btus of the different 

types of energy inputs by emissions 

factors for combustion of those fuel 

sources. The emission factors for the 

different fuel types are from GREET and 

are based primarily on assumed carbon 

contents of the different process fuels. 

The emissions from producing 

electricity are also taken from GREET 

and represent average U.S. grid 

electricity production emissions. The 

emissions from combustion of biomass 

fuel source are not assumed to increase 

net atmospheric CO2 levels the CO2

emitted from biomass-based fuels 

combustion does not increase 

atmospheric CO2 concentrations, 

assuming the biogenic carbon emitted is 

offset by the uptake of CO2 resulting 

from the growth of new biomass. 

Therefore, CO2 emissions from biomass 

combustion as a process fuel source are 

not included in the lifecycle GHG 

inventory of the ethanol plant. 

e. Fuel Transport 

Transportation and distribution of 

ethanol, biomass-based diesel, 

petroleum diesel and gasoline were also 

included in this analysis based on 

GREET defaults. The GREET defaults for 

25040 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

309 DOE/NETL. 2008. Development of Baseline 

Data and Analysis of Life Cycle Greenhouse Gas 

Emissions of Petroleum-Based Fuels. DOE/NETL– 

2009/1346. 

both ethanol and gasoline transport 

from plant/refinery to bulk terminals 

were used. The GREET defaults for both 

ethanol and gasoline distribution from 

the bulk terminal to the service station 

were also used. 

As with feedstock transport we have 

conducted a more detailed analysis of 

fuel transport and distribution impacts 

for use in criteria pollutant inventories 

(see DRIA Chapter 1.6) and for our cost 

analysis described in DRIA Chapter 4.2. 

Due to the timing of this analysis we 

were not able to incorporate the results 

in our proposed lifecycle calculation but 

plan to do that for the final rule. 

f. Tailpipe Combustion 

Combustion CO2 emissions for 

ethanol, biomass-based diesel, 

petroleum diesel and gasoline were 

based on the carbon content of the fuel. 

However, over the full lifecycle of the 

fuel, the CO2 emitted from biomassbased fuels combustion does not 

increase atmospheric CO2

concentrations, assuming the biogenic 

carbon emitted is offset by the uptake of 

CO2 resulting from the growth of new 

biomass. As a result, CO2 emissions 

from biomass-based fuels combustion 

are not included in their lifecycle 

emissions results. Net carbon fluxes 

from changes in biogenic carbon 

reservoirs in wooded or crop lands are 

accounted for separately in the land use 

change analysis as outlined in the 

agricultural sector modeling above. 

When calculating combustion GHG 

emissions, however, the methane and 

N2O emitted during biomass-based fuels 

combustion are included in the analysis. 

Unlike CO2 emissions, the combustion 

of biomass-based fuels does result in net 

additions of methane and N2O to the 

atmosphere. Therefore, combustion 

methane and N2O emissions are 

included in the lifecycle GHG emissions 

results for biomass-based fuels. 

Combustion related methane and N2O 

emissions for both biomass-based fuels 

and petroleum-based fuels are based on 

EPA MOVES model results. 

6. Petroleum Baseline 

To establish the lifecycle greenhouse 

gas emissions associated with the 

petroleum baseline against which the 

renewable fuels were compared, we 

used an updated version of the GREET 

model. Lifecycle energy use and 

associated emissions for petroleumbased fuels in GREET is calculated 

based on an energy efficiency metric for 

the different processes involved with 

petroleum-based fuels production. The 

energy efficiency metric is a measure of 

how many Btus of input energy are 

needed to make a Btu of product. 

GREET has assumptions on energy 

efficiency for different finished 

petroleum products as well as for 

different types of crude oil. 

We are using the latest version of the 

GREET model for this analysis (Version 

1.8b) which includes recent updates to 

the energy efficiencies of petroleum 

refining. To represent baseline 

petroleum fuels we have used the 2005 

estimates of actual gasoline and diesel 

fuel used. For 2005, 86% of gasoline 

and 92% of diesel fuel was produced 

domestically with the rest imported 

finished product. To represent 

international production we assume the 

same GHG refinery emissions from 

GREET as used domestically. We did 

not include indirect land use impacts in 

assessing the lifecycle GHG performance 

of the 2005 baseline fuel pool as we 

believe these would insignificantly 

impact the average performance 

assessment of the baseline. 

Additionally, consistent with our 

assessment of energy security impacts, 

we did not include as an indirect GHG 

impact the potential impact of 

maintaining a military presence. 

GREET also has assumptions on the 

mix of energy sources used to provide 

the energy input, which determine GHG 

emissions. For example if coal, natural 

gas, or purchased electricity is used as 

an energy source. The GHG emissions 

associated with petroleum fuel 

production are based on the emissions 

from producing and combusting the 

input energy sources needed, like GHG 

emissions from using natural gas at the 

petroleum refinery. Non-combustion 

GHG sources like fugitive methane 

emissions are added in where 

applicable. 

Based on the EISA requirements, we 

used the 2005 mix of crude as the 

petroleum baseline. We developed 

emissions factors for those crude types 

since they are not currently included in 

GREET. In 2005, 5% of crude was 

Canadian tar sand, 1% was Venezuela 

extra heavy, and 23% was heavy crude. 

For this proposal, we are using the 

average GHG emissions associated with 

the 2005 petroleum baseline, as required 

by EISA. However, we recognize that an 

additional gallon of renewable fuel 

replaces the marginal gallon of 

petroleum fuel. To the extent that the 

marginal gallon is from oil sands or 

other types of crude oil that are 

associated with higher than average 

GHG emissions, replacing these fuels 

could have a larger GHG benefit. 

Conversely to the extent the marginal 

gallon displaced is from imported 

gasoline produced from light crude, 

replacing these fuels would have a 

smaller GHG benefit. We solicit 

comment on whether—strictly for 

purposes of assessing the benefits of the 

rule (and not for purposes of 

determining whether certain renewable 

fuel pathways meet the GHG reduction 

thresholds set forth in EISA), we should 

assess benefits based on a marginal 

displacement approach and, if so, what 

assumptions we should use for the 

marginal displacements. 

In December 2008, the U.S. 

Department of Energy’s National Energy 

Technology Laboratory (NETL) released 

a report that estimates the average 

lifecycle GHG emissions from 

petroleum-based fuels sold or 

distributed in 2005.309 The estimates in 

the report are based on a slightly 

different methodology than EPA’s 

analysis of lifecycle GHG emissions for 

the petroleum baseline. The NETL 

report is available on the docket for this 

rulemaking. We invite comments on 

whether NETL’s analysis has significant 

implications for how EPA is estimating 

petroleum baseline lifecycle GHG 

emissions. 

7. Energy Sector Indirect Impacts 

Increased demand for natural gas to 

power corn ethanol plants could have 

additional impacts on the U.S. energy 

sector. As demand for natural gas 

increases, the use of natural gas in other 

sectors (e.g., electric generation) could 

decrease. For this analysis, we are using 

the NEMS model to project the 

secondary or indirect impacts on the 

energy sector. However, we were not 

able to include this analysis in the GHG 

emissions estimates presented in this 

proposal. We hope to have this analysis 

for the final rule. Additional details on 

the methodology are included in the 

DRIA Chapter 2, and we invite 

comments on this approach. 

We are assuming, for the proposal, 

that a gallon of renewable fuel replaces 

an energy equivalent gallon of 

petroleum fuel. This analysis presumes 

that petroleum-based fuels as they are 

currently produced will continue to be 

used for transportation fuels and will be 

replaced on a Btu for Btu basis. Many 

factors could affect this assumption 

including advances in petroleum fuel 

technology, availability of other fossil 

fuels for transportation use, and of 

course the supply and cost of 

petroleum. We have not tried to analyze 

these potential impacts in this rule. 

However we invite comment on such an 

approach. 

We have also not assessed whether 

expanded use of biofuels in the U.S. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25041 

310For this proposal, our preliminary analysis 

suggests land use impacts of petroleum production 

for the fuels used in the U.S. in 2005 would not 

have an appreciable impact on the 2005 baseline 

GHG emissions assessment. However, we expect to 

more carefully consider potential land use impacts 

of petroleum-based fuel production for the final 

rule and invite comment and information that 

would support such an analysis. 

311 2005 petroleum baseline fuel production 

includes crude oil extraction, transportation, 

refining, and transport of finished product. 

312Ethanol tailpipe emissions include CH4 and 

N2O emissions but not CO2 emissions as these are 

assumed to be offset by feedstock carbon uptake. 

will impact the energy markets in other 

countries. For example, reducing 

demand for petroleum-based fuel in the 

U.S. may reduce worldwide petroleum 

prices and impact the use of petroleum 

in other countries. We invite comment 

on how best to assess these potential 

impacts and will attempt to do so for the 

final rule. 

C. Fuel Specific GHG Emissions 

Estimates 

While the results presented in this 

section represent the most up-to-date 

information currently available, this 

analysis is part of an ongoing process. 

Because lifecycle analysis is a new part 

of the RFS program, in addition to the 

formal comment period on the proposed 

rule, EPA is making multiple efforts to 

solicit public and expert feedback on 

our proposed approach. As discussed in 

Section XI, EPA plans to hold a public 

workshop focused specifically on 

lifecycle analysis during the comment 

period to assure full understanding of 

the analyses conducted, the issues 

addressed and options that should be 

considered. We expect that this 

workshop will allow the most 

thoughtful and useful comments to this 

proposal and assure the best 

methodology and assumptions are used 

for calculating GHG emissions impacts 

of fuels for the final rule. Additionally 

we will conduct peer-reviews of key 

components of our analysis. As part of 

ongoing analysis for the final rule, EPA 

will seek peer review of: Our use of 

satellite data to project future land use 

changes; the land conversion GHG 

emissions factors estimated by Winrock; 

our estimates of GHG emissions from 

foreign crop production; methods to 

account for the variable timing of GHG 

emissions; and how models are used 

together to provide overall lifecycle 

GHG estimates. 

In addition to the refinements to the 

methodology that we plan to undertake 

for the final rule, we also intend to 

update our results periodically. EPA 

recognizes that the state of the science 

for lifecycle GHG analysis will continue 

to evolve over time as new data and 

modeling techniques become available 

and as there are improvements in 

agricultural and renewable fuel 

production practices as well as new 

feedstocks. We invite comments on the 

appropriate amount of time for periodic 

review of the lifecycle assessment 

methodology, but we propose that 

performing an update of the 

methodology every 3–5 years would be 

appropriate. We would expect the first 

update to this analysis would occur 

closer to 3 years. This timeframe would 

allow us to undergo a formal review 

process after the final rule to ensure that 

this methodology takes into account the 

most state-of-the-art science and reflects 

the input of appropriate experts in this 

field. However, any change in lifecycle 

methodology as contemplated here 

would not affect the eligibility of 

biofuels produced at facilities covered 

by the grandfathering provisions of 

EISA at section 211(o)(4)(g). 

1. Greenhouse Gas Emissions 

Reductions Relative to the 2005 

Petroleum Baseline 

In this section we present detailed 

lifecycle GHG results for several specific 

biofuels representing a range biofuel 

pathways. This section also includes the 

results of sensitivity analysis for key 

variables. The sensitivity of the time 

period and discount rate are discussed 

below. In the rest of this section we 

focus on two sets of lifecycle GHG 

results. One set of results that uses a 100 

year time period and 2% discount rate 

and a parallel set of results using a 30 

year time period and a 0% discount 

rate. In Section IV.C.2 which follows, 

we also present the results for some 

additional combinations of time horizon 

for assessing GHG emission changes as 

well as assuming other discount rates. 

Additional pathways, not included in 

the results presented in this section, 

distinguishing other combinations of 

feedstock and processing technologies 

have been evaluated. These additional 

pathways are described in detail in the 

DRIA and are included in these 

proposed regulations. 

a. Corn Ethanol 

Table VI.C.1–1 presents the breakout 

of the net present value of lifecycle GHG 

emissions per million British thermal 

unit (mmbtu) of corn ethanol and 

gasoline. The results are broken out by 

lifecycle stage. Values are shown for a 

standard dry mill corn ethanol plant in 

2022 using natural gas for process 

energy and drying the co-product of 

distillers grains (DGs). Results indicate 

where the major contributions of GHG 

emissions are across the fuel lifecycle. 

Fuel processing and indirect land use 

change are the main contributors to corn 

ethanol lifecycle GHG emissions. Net 

domestic and international agricultural 

impacts (w/o land use change) include 

direct and indirect impacts, such as 

reductions in livestock enteric 

fermentation. 

TABLE VI.C.1–1—ABSOLUTE LIFECYCLE GHG EMISSIONS FOR CORN ETHANOL AND THE 2005 PETROLEUM BASELINE

[CO2-eq/mmBtu] 

2005 Gasoline 

baseline 

Natural gas 

dry mill with 

dry DGs 

2005 Gasoline 

baseline 

Natural gas 

dry mill with 

dry DGs 

Lifecycle Stage 100 yr 2% 30 yr 0% 

Net Domestic Agriculture (w/o land use change) ............................................ N/A ¥499,029 N/A ¥347,365 

Net International Agriculture (w/o land use change) ....................................... N/A 452,118 N/A 314,711 

Domestic Land Use Change ........................................................................... N/A 79,547 N/A 92,575 

International Land Use Change ....................................................................... N/A310 1,911,391 N/A 1,910,822 

Fuel Production 311 .......................................................................................... 823,262 1,404,083 573,058 977,358 

Fuel and Feedstock Transport ........................................................................ (see footnote 

321) 

174,327 ........................ 121,346 

Tailpipe Emissions 312 ...................................................................................... 3,417,311 37,927 2,378,800 26,400 

Net Total Emissions ................................................................................. 4,240,674 3,560,365 2,951,858 3,095,846 

25042 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

313The treatment of emissions over time is not 

critical if international land use change emissions 

are excluded because the results without land use 

change are consistent over time. Therefore the 

overall lifecycle GHG results do not vary with time 

or discount rate assumptions. 

Table VI.C.1–1 demonstrates the 

importance of the discount rate and 

time period analyzed as well as the 

importance of significance of including 

GHG emissions from international land 

use changes. Assuming 100 years of 

corn ethanol produced in a basic dry 

mill ethanol production facility and 

using a 2% discount rate results in corn 

ethanol having a 16% reduction in GHG 

emissions compared to the 2005 

baseline gasoline assumed to be 

replaced. In contrast, assuming 30 years 

of corn ethanol production and use and 

no discounting of the GHG emission 

impacts results in predicting that corn 

ethanol will have a 5% increase in GHG 

emissions compared to petroleum 

gasoline. 

As discussed in Section VI.B.2.a, 

EPA’s interpretation of the EISA statute 

compels us to include significant 

indirect emission impacts including 

those due to land use changes in other 

countries. The data in Table VI.C.1–1 

indicate that excluding the international 

land use change would result in corn 

ethanol having an approximately 60% 

reduction in lifecycle GHG emissions 

compared to petroleum gasoline 

regardless of the timing or discount rate 

used.313

In Table VI.C.1–1, we project a 

standard dry mill ethanol plant in 2022 

using corn as its feedstock, using natural 

gas for process energy, and drying the 

co-product of distillers grains (DGs). 

Different corn ethanol production 

technologies will have different 

lifecycle GHG results. For example, due 

to its high carbon content, using coal as 

the process energy source significantly 

worsens the lifecycle GHG impact of 

ethanol produced at such a facility. On 

the other hand, replacing natural gas 

with renewable biomass as the process 

energy source greatly improves the GHG 

assessment. 

Other technology options are 

available to improve the efficiency of 

ethanol facilities. Table VI.C.1–2 shows 

the impact that different corn ethanol 

production process pathways will have 

on the overall lifecycle GHG results. 

Table VI.C.2–2 shows that currently 

available technologies could be applied 

to corn ethanol plants to reduce their 

net GHG emissions. 

For example, a combined heat and 

power (CHP) configuration, used in 

combination with corn oil fractionation, 

would result in a GHG emissions 

reduction of 27% relative to the 2005 

petroleum baseline over 100 years using 

a 2% discount rate, and a 6% reduction 

over 30 years with no discounting. In 

addition, advanced technologies such as 

membrane separation and raw starch 

hydrolysis could improve the emissions 

associated with corn ethanol production 

even more substantially. Combining all 

of these technologies in a state-of-the-art 

natural gas powered corn ethanol 

facility would produce ethanol that has 

approximately 35% less lifecycle GHG 

emissions than an energy equivalent 

amount of baseline gasoline displaced 

over 100 years using a 2% discount rate 

and, by comparison a 14% reduction 

when accounting for 30 years of 

emission changes but applying no 

discounting. Details on these different 

technologies are included in the DRIA 

Chapter 1.5. 

Table VI.C.1–2 also shows that the 

choice of drying DGs can have a 

significant impact on the GHG 

emissions associated with an ethanol 

plan, since drying the ethanol 

byproduct is an energy intensive 

process. However, wet DGs are only 

suitable where a local market is 

available such as a dairy farm or cattle 

feedlot, since wet DGs are highly 

perishable. 

TABLE VI.C.1–2—LIFECYCLE GHG EMISSIONS CHANGES FOR VARIOUS CORN ETHANOL PATHWAYS IN 2022 RELATIVE TO

THE 2005 PETROLEUM BASELINE

Corn ethanol production plant type 

Percent 

change from 

2005 petroleum baseline 

(100 yr 2%) 

Percent 

change from 

2005 baseline 

(30 yr 0%) 

Natural Gas Dry Mill with dry DGs .......................................................................................................................... ¥16 +5 

Natural Gas Dry Mill with dry DGs and CHP .......................................................................................................... ¥19 +2 

Natural Gas Dry Mill with dry DGs, CHP, and Corn Oil Fractionation ................................................................... ¥27 ¥6 

Natural Gas Dry Mill with dry DGs, CHP, Corn Oil Fractionation, and Membrane Separation ............................. ¥30 ¥10 

Natural Gas Dry Mill with dry DGs, CHP, Corn Oil Fractionation, Membrane Separation, and Raw Starch Hydrolysis ................................................................................................................................................................. ¥35 ¥14 

Natural Gas Dry Mill with wet DGs ......................................................................................................................... ¥27 ¥6 

Natural Gas Dry Mill with wet DGs and CHP ......................................................................................................... ¥30 ¥9 

Natural Gas Dry Mill with wet DGs, CHP, and Corn Oil Fractionation ................................................................... ¥33 ¥12 

Natural Gas Dry Mill with wet DGs, CHP, Corn Oil Fractionation, and Membrane Separation ............................. ¥36 ¥15 

Natural Gas Dry Mill with wet DGs, CHP, Corn Oil Fractionation, Membrane Separation, and Raw Starch Hydrolysis ................................................................................................................................................................. ¥39 ¥18 

Coal Fired Dry Mill with dry DGs ............................................................................................................................. +13 +34 

Coal Fired Dry Mill with dry DGs and CHP ............................................................................................................. +10 +31 

Coal Fired Dry Mill with dry DGs, CHP, and Corn Oil Fractionation ...................................................................... ¥5 +15 

Coal Fired Dry Mill with dry DGs, CHP, Corn Oil Fractionation, and Membrane Separation ................................ ¥13 +8 

Coal Fired Dry Mill with dry DGs, CHP, Corn Oil Fractionation, Membrane Separation, and Raw Starch Hydrolysis ....................................................................................................................................................................... ¥21 ¥1 

Coal Fired Dry Mill with wet DGs ............................................................................................................................ ¥9 +12 

Coal Fired Dry Mill with wet DGs and CHP ............................................................................................................ ¥11 +10 

Coal Fired Dry Mill with wet DGs, CHP, and Corn Oil Fractionation ..................................................................... ¥17 +3 

Coal Fired Dry Mill with wet DGs, CHP, Corn Oil Fractionation, and Membrane Separation ............................... ¥25 ¥4 

Coal Fired Dry Mill with wet DGs, CHP, Corn Oil Fractionation, Membrane Separation, and Raw Starch Hydrolysis ................................................................................................................................................................. ¥30 ¥9 

Biomass Fired Dry Mill with dry DGs ...................................................................................................................... ¥39 ¥18 

Biomass Fired Dry Mill with wet DGs ...................................................................................................................... ¥40 ¥19 

Natural Gas Fired Wet Mill ...................................................................................................................................... ¥7 +14 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25043 

TABLE VI.C.1–2—LIFECYCLE GHG EMISSIONS CHANGES FOR VARIOUS CORN ETHANOL PATHWAYS IN 2022 RELATIVE TO

THE 2005 PETROLEUM BASELINE—Continued 

Corn ethanol production plant type 

Percent 

change from 

2005 petroleum baseline 

(100 yr 2%) 

Percent 

change from 

2005 baseline 

(30 yr 0%) 

Coal Fired Wet Mill .................................................................................................................................................. +20 +41 

Biomass Fired Wet Mill ............................................................................................................................................ ¥47 ¥26 

As described in Sections VI.A and 

VI.B, there are a number of parameters 

and modeling assumptions that could 

impact the overall renewable fuel GHG 

results. The estimates in Table VI.C.1– 

2 are based on the GHG emissions for 

a specific change in volumes analyzed 

in 2022 (12.3 to 15 Bgal). These volumes 

represent the change in corn ethanol 

production that would occur in 2022 

without and then with EISA mandates 

in place. The GHG impact is then 

normalized to a per gallon or Btu basis 

in relation to gasoline. These values are 

used to represent every gallon of corn 

ethanol produced throughout the 

program. 

There are several important 

implications associated with this 

methodology. First, this analysis focuses 

on the average impact of an increase in 

fuel produced using a technology 

pathway and does not distinguish the 

emission performance between biofuel 

production plants using the same basic 

production technology and type of 

feedstock. Thus it does not account for 

any incremental differences in facility 

design or operation which may affect 

the lifecycle GHG performance at that 

facility. Second, by focusing on 2022, 

this analysis does not track how biofuel 

GHG emission performance may change 

over time between now and 2022. Third, 

the results presented here are based on 

the GHG impacts of the volumes 

analyzed. 

For this proposal, we believe that 

using the emissions assessment from a 

typical 2022 facility for each major 

technology pathway captures the 

appropriate level of detail needed to 

determine whether a particular biofuel 

meets the threshold requirements in 

EISA. To address whether the GHG 

emissions vary significantly over time, 

we also calculated corn ethanol lifecycle 

GHG emissions estimates in 2012 and 

2017. As shown in Table VI.C.1–3, corn 

ethanol’s lifecycle GHG emissions 

reductions are fairly consistent 

regardless of which base year is 

analyzed. This may be due to 

countervailing forces that stabilize land 

use change emissions over the period of 

our analysis. Crop yields increase over 

time (therefore reducing land use 

pressure), but there is also increasing 

production of other renewable fuels that 

require land for feedstock production 

(therefore increasing land use pressure). 

Although we are proposing to use 2022 

as the base year for our lifecycle GHG 

emissions estimates, we invite 

comments on this approach. 

TABLE VI.C.1–3—CORN ETHANOL LIFECYCLE GHG EMISSIONS CHANGES IN 2012, 2017, AND 2022 

Scenario Description 

Percent 

change from 

2005 petroleum baseline 

(100 yr 2%) 

Percent 

change from 

2005 petroleum baseline 

(30 yr 0%) 

Corn Ethanol Natural Gas Dry Mill in 2012 with dry DGs ...................................................................................... ¥16 ¥3 

Corn Ethanol Natural Gas Dry Mill in 2017 with dry DGs ...................................................................................... ¥13 +9 

Corn Ethanol Natural Gas Dry Mill in 2022 with dry DGs ...................................................................................... ¥16 +5 

We also tested the impact of analyzing 

a larger change in corn ethanol volumes 

on the GHG emissions estimates. Table 

VI.C.1–4 shows the sensitivity of our 

analysis to the volume changes 

analyzed. Based on this scenario, the 

GHG emissions estimates associated 

with a larger change (6.3 Bgal) in corn 

ethanol volumes (8.7 Bgal to 15 Bgal) 

results in lower GHG emission 

reductions. Additional details on these 

sensitivity analyses are included in the 

DRIA Chapter 2. 

TABLE VI.C.1–4—CORN ETHANOL LIFECYCLE GHG EMISSIONS CHANGES ASSOCIATED WITH DIFFERENT VOLUME

CHANGES

Scenario Description 

Percent 

Change from 

2005 

Petroleum 

Baseline 

(100 yr 2%) 

Percent 

Change from 

2005 

Petroleum 

Baseline 

(30 yr 0%) 

Corn Ethanol Natural Gas Dry Mill in 2022 with dry DGs; 2.7 Bgal change in corn ethanol volumes .................. ¥16 +5 

Corn Ethanol Natural Gas Dry Mill in 2022 with dry DGs; 6.3 Bgal change in corn ethanol volumes .................. ¥6 +14 

The results presented in previous 

tables assume that managed pasture 

(i.e., land actively used for livestock 

grazing) converted from pasture to 

cropland would be replaced with new 

pasture in other areas. The area of 

25044 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

314 Goldemberg, J.; Coelho, ST.; Guardabassi, PM. 

The sustainability of ethanol production from 

sugarcane. Energy Policy. 2008. doi:10.1016/ 

j.enpol.2008.02.028. 

managed pasture converted to cropland 

was estimated using satellite data from 

Winrock and land cover data from 

GTAP. As a sensitivity analysis, we also 

analyzed a scenario in which none of 

the pastureland converted to cropland 

would be replaced if, for example, 

livestock production could be more 

intensively developed on the remaining 

pasture (see first row in Table VI.C.1–5). 

Similarly, we also calculated results 

assuming that all pasture acres would be 

replaced (second row in Table VI.C.1– 

5). Finally, the third row of Table 

VI.C.1–5 includes lifecycle GHG results 

assuming that all of the land converted 

to cropland would come from pasture 

and that none of that pasture would be 

replaced, which is counter to the land 

use trends identified by the Winrock 

satellite data. As can be seen, the 

assumption of pastureland replacement 

can have a significant effect on the 

results. We ask for comment on the best 

assumptions to be made when 

considering the need to replace pasture 

that has been converted to crop 

production. We note that the best 

decision on pasture land replacement 

may vary by country or region due to 

such factors as the current intensity of 

use of pasture land as well as trends in 

demand for pasture. DRIA Chapter 2 

includes more details about the 

treatment of pasture conversion, and 

sensitivity analysis of the types land use 

changes induced by corn ethanol 

production. 

TABLE VI.C.1–5—CORN ETHANOL LIFECYCLE GHG EMISSIONS CHANGES ASSOCIATED WITH DIFFERENT ASSUMPTIONS ON

LAND USE CHANGES

Scenario Description 

Percent 

Change from 

2005 Petroleum Baseline 

(100 yr 2%) 

Percent 

Change from 

2005 Petroleum Baseline 

(30 yr 0%) 

Corn Ethanol Natural Gas Dry Mill in 2022 with dry DGs; 0% pastureland replaced ............................................ ¥34 ¥19 

Corn Ethanol Natural Gas Dry Mill in 2022 with dry DGs; 100% pastureland replaced ........................................ ¥2 +24 

Corn Ethanol Natural Gas Dry Mill in 2022 with dry DGs; grassland only conversion and 0% pastureland replaced ................................................................................................................................................................... ¥48 ¥38 

DRIA Chapter 2 includes results for 

additional sensitivity analysis of corn 

ethanol lifecycle GHG emissions. We 

also intend to conduct additional 

sensitivity analysis for the final rule. We 

invite comment on these assumptions. 

b. Imported Ethanol 

Table VI.C.1–6 presents the breakout 

of lifecycle GHG emissions for 

sugarcane ethanol compared to a 2005 

petroleum baseline under different 

discount rate and time horizon 

scenarios and land use assumptions. 

This assessment was based on applying 

the same methodology as for other 

biofuels including the assessment of 

both direct and indirect impacts using 

the combination of FASOM, FAPRI and 

Winrock modeling results. Virtually all 

the ethanol from sugarcane is expected 

to be imported from Brazilian 

production. Applying the proposed 

FAPRI/Winrock methodology to 

sugarcane ethanol production in Brazil 

predicts a large increase in new acres 

planted, which has a relatively large 

impact on overall GHG emissions. The 

impact is from both new sugarcane 

production acres in Brazil resulting in 

land use change but also reduced 

commodity exports from Brazil resulting 

in land use change in other countries. 

The proposed FAPRI/Winrock 

methodology predicts that new crop 

acreage is converted from a range of 

land types. In contrast, some studies 

suggest that sugarcane ethanol 

production can increase in Brazil by 

relying on existing excess pasture lands 

and will not significantly impact other 

land types.314 Table VI.C.1–6 provides 

the range of lifecycle GHG emission 

reduction results under these different 

assumptions of type conversion 

patterns. As a sensitivity analysis, 

shows results for a scenario where none 

of the grassland converted to cropland 

in Brazil would be replaced if, for 

example, livestock production could be 

more intensively developed on the 

remaining pasture (see second row in 

Table VI.C.1–6). The third row of Table 

VI.C.1–6 includes lifecycle GHG results 

assuming that in Brazil all of the land 

converted to cropland would come from 

grassland and that none of that 

grassland would be replaced. As can be 

seen in the table, the assumption of 

pastureland replacement can have an 

important effect on the results. DRIA 

Chapter 2 includes more details about 

the treatment of pasture conversion, and 

sensitivity analysis of the types land use 

changes induced by sugarcane ethanol 

production. 

TABLE VI.C.1–6—SUGARCANE ETHANOL GHG EMISSION CHANGES UNDER VARIED LAND USE ASSUMPTIONS AND VARIED

DISCOUNT RATES AND TIME HORIZONS RELATIVE TO 2005 PETROLEUM BASELINE

Land Use Change Scenario Description (100 yr 2%) (30 yr 0%) 

FAPRI/Winrock estimate with managed pasture replacement ................................................................................ ¥44 ¥26 

FAPRI/Winrock estimate with no pasture replacement in Brazil ............................................................................ ¥59 ¥45 

Only grassland conversion in Brazil and no pasture replacement in Brazil ........................................................... ¥64 ¥52 

We are aware that recent land use 

enforcement policies in Brazil may shift 

cropland expansion patterns (see also 

Section VI.B.5.b.iii). We seek comment 

on both pasture conversion patterns and 

Brazil land use enforcement policy 

impacts. We are conducting more 

detailed economic modeling of the 

Brazilian agricultural sector by state for 

inclusion in FAPRI to address pasture, 

enforcement and other assumptions for 

the final rule. State level production 

data could be used in conjunction with 

Winrock’s state level satellite data, 

which may substantially change the 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25045 

estimates of the location and type of 

land being converted in Brazil for the 

final rule. 

We have also assumed that sugarcane 

ethanol production relies on burning 

bagasse as an energy source and that the 

process produces excess electricity. We 

factor in credits from this excess 

electricity based on offsetting the 

Brazilian electricity grid. As Brazil 

implements limits on field burning of 

bagasse there may be additional bagasse 

used at sugarcane ethanol plants and 

additional electricity production. We 

plan to look at this further for the final 

rule analysis. 

c. Cellulosic Ethanol 

Given that commercially-viable 

cellulosic ethanol production is not yet 

a reality, analysis of this pathway relies 

upon significant assumptions regarding 

the development of production 

technologies. As described in the 

previous section, our analysis assumed 

corn stover required no international 

land use changes, since corn stover does 

not compete with other crops for 

acreage in the U.S. Therefore, using corn 

stover as a feedstock for cellulosic 

biofuel production would not have an 

impact on U.S. exports. We assumed 

some of the nutrients would have to be 

replaced through higher fertilizer rates 

on acres where stover is removed; 

however, increased stover removal was 

also associated with higher rates of 

reduced tillage or no tillage practices 

which results in soil carbon increase. 

See Section IX.A for details. In addition, 

cellulosic ethanol was assumed to be 

produced using the biochemical process 

which is expected to produce more 

electricity from the lignin in the 

feedstock than is required to power the 

ethanol plant, so excess electricity can 

be sold back to the grid. See DRIA 

Chapter 2 for additional details. This 

electricity provides a GHG benefit, 

which results in GHG emissions 

reductions from fuel production as 

shown in Table VI.C.1–7. 

TABLE VI.C.1–7—ABSOLUTE LIFECYCLE GHG EMISSIONS FOR CORN STOVER CELLULOSIC ETHANOL AND THE 2005 

PETROLEUM BASELINE

[CO2-eq/mmBtu] 

2005 

Petroleum 

baseline 

Corn stover 

ethanol (selling excess 

electricity to 

grid) 

2005 

Petroleum 

baseline 

Corn stover 

ethanol (selling excess 

electricity to 

grid) 

Lifecycle Stage (100 yr 2%) (30 yr 0%) 

Net Domestic Agriculture (w/o land use change) ............................................ ........................ 178,862 N/A 124,503 

Net International Agriculture (w/o land use change) ....................................... ........................ 0 N/A ........................

Domestic Land Use Change ........................................................................... ........................ ¥78,448 N/A ¥91,925 

International Land Use Change ....................................................................... ........................ 0 N/A 0 

Fuel Production ................................................................................................ 823,262 ¥875,424 573,058 ¥609,367 

Fuel and Feedstock Transport ........................................................................ ........................ 107,214 ........................ 74,629 

Tailpipe Emissions ........................................................................................... 3,417,311 37,927 2,378,800 26,400 

Net Total Emissions ................................................................................. 4,240,674 ¥629,870 2,951,858 ¥475,130 

Although switchgrass must compete 

with other crops for land in the U.S., 

average switchgrass ethanol yields are 

on average higher than corn ethanol 

yields (approximately 580 gallons/acre 

compared to 480 gallons/acre). 

Therefore, switchgrass would need 

approximately 20% less land to produce 

the same amount of ethanol compared 

to corn. In addition, FASOM predicts 

that switchgrass would generally be 

grown on more marginally productive 

land. Since switchgrass is not projected 

to displace crop acres with high yields, 

new switchgrass acres generally would 

not have a large impact on exports. 

Therefore, the international land use 

change impacts are modest. Like 

cellulosic ethanol from corn stover, 

switchgrass ethanol is also assumed to 

produce excess electricity that can be 

sold to the grid, therefore switchgrass 

cellulosic ethanol results in relatively 

large lifecycle GHG reductions 

compared to the replaced petroleum 

gasoline as shown in Table VI.C.1–8. 

TABLE VI.C.1–8—ABSOLUTE GHG EMISSIONS FOR SWITCHGRASS CELLULOSIC ETHANOL AND THE 2005 PETROLEUM

BASELINE

[CO2-eq/mmBtu] 

2005 

Petroleum 

baseline 

Switchgrass 

ethanol (selling excess 

electricity to 

grid) 

2005 

Petroleum 

baseline 

Switchgrass 

ethanol (selling excess 

electricity to 

grid) 

Lifecycle Stage (100 yr 2%) (30 yr 0%) 

Net Domestic Agriculture (w/o land use change) ............................................ ........................ ¥470,620 ........................ ¥327,590 

Net International Agriculture (w/o land use change) ....................................... ........................ ¥356,712 ........................ ¥248,301 

Domestic Land Use Change ........................................................................... ........................ ¥65,318 ........................ ¥76,015 

International Land Use Change ....................................................................... ........................ 423,097 ........................ 424,094 

Fuel Production ................................................................................................ 823,262 ¥874,599 573,058 ¥608,793 

Fuel and Feedstock Transport ........................................................................ ........................ 136,663 ........................ 95,129 

Tailpipe Emissions ........................................................................................... 3,417,311 37,927 2,378,800 26,400 

25046 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

TABLE VI.C.1–8—ABSOLUTE GHG EMISSIONS FOR SWITCHGRASS CELLULOSIC ETHANOL AND THE 2005 PETROLEUM

BASELINE—Continued 

[CO2-eq/mmBtu] 

2005 

Petroleum 

baseline 

Switchgrass 

ethanol (selling excess 

electricity to 

grid) 

2005 

Petroleum 

baseline 

Switchgrass 

ethanol (selling excess 

electricity to 

grid) 

Net Total Emissions ................................................................................. 4,240,674 ¥1,169,561 2,951,858 ¥715,076 

Cellulosic ethanol does not have 

nearly as significant an impact on land 

use as other biofuels, therefore we did 

not calculate sensitivity impacts of, for 

example, assuming full replacement of 

pasture versus no pasture replacement 

which could be important in the 

lifecycle GHG assessment of other 

biofuels. As the land use issue is not 

critical for the cellulosic feedstock fuels 

in the scenarios we analyzed, the impact 

of timing and discount rates also do not 

have a significant impact on the overall 

results for cellulosic ethanol. Both of the 

cellulosic ethanol pathways we 

examined, switchgrass and corn stover 

using enzymatic processing, reduced 

lifecycle GHG emissions by significantly 

more than the 60% threshold for 

cellulosic biofuel. Table VI.C.1–9 

summarizes the lifecycle GHG results 

for cellulosic ethanol fuel pathways. 

TABLE VI.C.1–9—CELLULOSIC ETHANOL GHG EMISSION CHANGES FROM DIFFERENT FEEDSTOCKS AND VARIED

DISCOUNT RATES AND TIME HORIZONS RELATIVE TO 2005 PETROLEUM BASELINE

[In percent] 

Assumption—feedstock type (100 yr 2%) (30 yr 0%) 

Corn Stover .................................................................................................................................................. ¥115 ¥117 

Switchgrass .................................................................................................................................................. ¥128 ¥121 

d. Biodiesel 

EPA’s modeling predicts that 

soybean-based biodiesel production has 

a large land use impact for two major 

reasons. Soybean biodiesel has a 

relatively low gallon per acre yield 

(approximately 65 gal/acre for soybean 

biodiesel versus 480 gal/acre for corn 

ethanol). Thus, the impact of any landuse change tends to be magnified with 

soybean biodiesel. Even when the 

higher Btu value of biodiesel is taken 

into consideration, Btu/acre yields are 

still significantly lower for biodiesel 

than for ethanol (approximately 97 gal/ 

acre ethanol equivalent). Furthermore, 

our analysis suggests that due to high 

world wide demand for soybeans for 

food, cooking and other non-biofuel 

uses, soybean and other edible oils used 

for biofuel are generally replaced by 

production in other countries including 

production in tropical climates where 

the GHG emissions released per acre of 

converted land are highest. This 

indicates that soy-based biodiesel 

lifecycle GHG emissions could be 

greatly reduced with the adoption of 

policies and agricultural practices that 

limit the amount of tropical 

deforestation induced by soy-based 

biodiesel production. DRIA Chapter 2 

includes sensitivity analyses about the 

types of land converted to crops as a 

result of soy-based biodiesel production. 

Table VI.C.1–10 presents the breakout of 

the absolute lifecycle GHG emissions for 

soybean biodiesel and the petroleum 

diesel fuel baseline by lifecycle stage. 

TABLE VI.C.1–10—ABSOLUTE LIFECYCLE GHG EMISSIONS FOR SOYBEAN BIODIESEL AND THE 2005 PETROLEUM

BASELINE

[CO2-eq/mmBtu] 

2005 Petroleum baseline Soybean 

biodiesel 

2005 Petroleum baseline Soybean 

biodiesel 

Lifecycle Stage (100 yr 2%) (30 yr 0%) 

Net Domestic Agriculture (w/o land use change) ............................................ ........................ ¥423,206 ........................ ¥294,586 

Net International Agriculture (w/o land use change) ....................................... ........................ 195,304 ........................ 135,948 

Domestic Land Use Change ........................................................................... ........................ ¥8,980 ........................ ¥10,451 

International Land Use Change ....................................................................... ........................ 2,474,074 ........................ 2,469,574 

Fuel Production ................................................................................................ 749,132 838,490 521,458 583,658 

Fuel and Feedstock Transport ........................................................................ ........................ 149,258 ........................ 103,896 

Tailpipe Emissions ........................................................................................... 3,424,635 30,169 2,383,828 21,000 

Net Total Emissions ................................................................................. 4,173,768 3,255,109 2,905,286 3,009,039 

Our analysis is based on a change in 

biodiesel volumes from 0.4 Bgal to 0.7 

Bgal. Similar to the analysis we 

conducted for corn-ethanol, we plan to 

run a sensitivity analysis on the impact 

of using different volumes for the final 

rule. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25047 

As discussed in Section VI.B.2.a, 

EPA’s interpretation of the EISA statute 

compels us to include significant 

indirect emission impacts including 

those due to land use changes in other 

countries. The data in Table VI.C.1–10 

indicate that excluding the international 

land use change would result in soybased biodiesel having an 

approximately 80% reduction in 

lifecycle GHG emissions compared to 

petroleum gasoline regardless of the 

timing or discount rate used. The 

treatment of emissions over time is not 

critical if international land use change 

emissions are excluded because the 

results without land use change are 

consistent over time. Therefore the 

overall lifecycle GHG results do not vary 

with time or discount rate assumptions. 

In contrast, GHG emissions from 

waste oil and greases are assumed to 

have no land use impacts. We assumed 

any land use change was attributed to 

the original use of the feedstock, for 

example, soy oil was produced for the 

purpose of using for cooking and the 

land required to produce this cooking 

oil is properly attributed to that use. 

Gathering and re-using the left over 

waste cooking oil would have no 

additional land use impact. This lack of 

land use impact greatly influences the 

lifecycle GHG analysis. Table VI.C.1–11 

presents the breakout of the absolute 

lifecycle GHG emissions for waste 

grease biodiesel and the petroleum 

diesel fuel baseline by lifecycle stage. 

TABLE VI.C.1–11—ABSOLUTE LIFECYCLE GHG EMISSIONS FOR WASTE GREASE BIODIESEL AND THE 2005 PETROLEUM

BASELINE

[CO2-eq/mmBtu] 

2005 

Petroleum 

baseline 

Waste grease 

biodiesel 

2005 

Petroleum 

baseline 

Waste grease 

biodiesel 

Lifecycle Stage (100 yr 2%) (30 yr 0%) 

Net Domestic Agriculture (w/o land use change) ............................................ ........................ 0 ........................ 0 

Net International Agriculture (w/o land use change) ....................................... ........................ 0 ........................ 0 

Domestic Land Use Change ........................................................................... ........................ 0 ........................ 0 

International Land Use Change ....................................................................... ........................ 0 ........................ 0 

Fuel Production ................................................................................................ 749,132 658,198 521,458 458,160 

Fuel and Feedstock Transport ........................................................................ ........................ 149,258 ........................ 103,896 

Tailpipe Emissions ........................................................................................... 3,424,635 30,169 2,383,828 21,000 

Net Total Emissions ................................................................................. 4,173,768 837,626 2,905,286 583,056 

Table VI.C.1–12 summarizes the 

lifecycle GHG results for biodiesel fuel 

pathways. As the waste grease biodiesel 

is not assumed to have any land use 

impact the choice of timing or discount 

rate does not impact the waste grease 

biodiesel results. However, as the 

soybean biodiesel is found to have a 

large land use impact the choice of 

timing and discount rate has a big 

impact on the soybean biodiesel results. 

TABLE VI.C.1–12—BIODIESEL LIFECYCLE GHG EMISSION CHANGES FROM DIFFERENT FEEDSTOCKS AND VARIED

DISCOUNT RATES AND TIME HORIZONS RELATIVE TO 2005 PETROLEUM BASELINE

Assumption—feedstock type (100 yr 2%) (30 yr 0%) 

Soybean ....................................................................................................................................................... ¥22% +4% 

Waste Grease .............................................................................................................................................. ¥80% ¥80% 

Table VI.C.1–13 shows the sensitivity 

of our assessment for soy oil biodiesel 

assuming 100% of the grassland 

converted to cropland is replaced 

compared to an assumption that none of 

this grassland is replaced for livestock 

grazing. DRIA Section 2.8.2.4 provides 

more information about sensitivity 

analysis for the pasture replacement 

assumptions. 

TABLE VI.C.1–13—SOY-BASED BIODIESEL GHG EMISSION CHANGES UNDER VARIED LAND USE ASSUMPTIONS AND

VARIED DISCOUNT RATES AND TIME HORIZONS RELATIVE TO 2005 PETROLEUM BASELINE

Assumption—land types available for conversion (100 yr 2%) (30 yr 0%) 

100% Pasture Replacement ........................................................................................................................ ¥4% +27% 

No Pasture Replacement ............................................................................................................................ ¥45% ¥27% 

2. Treatment of GHG Emissions Over 

Time 

As described in Section VI.B.5, 

changes in indirect land use associated 

with increased biofuel production result 

in GHG emissions increases that 

accumulate over a long time period. 

Since there is a large release of carbon 

in the first year of land conversion, it 

can take many years for the benefits of 

the biofuel to make up for these early 

carbon emissions, depending on the 

specific biofuel in question. Table 

VI.C.2–1 contains the payback period 

associated with several types of biofuels 

and fuel production pathways. A 

payback period of 0 indicates that these 

pathways do not have land use change 

impacts and therefore reduce emissions 

in the first year that they are produced. 

Assessments are made in comparison to 

25048 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

315 Dry Mill corn ethanol plant using natural gas 

with 2022 energy use and dry DDGS. 

316Payback periods were not calculated for 

ethanol made from corn starch for the advanced 

biofuel reduction goals of 50% and 60% since this 

corn ethanol does not qualify under EISA as a 

potential advanced biofuel. 

317 Dry Mill corn ethanol plant using natural gas 

with 2022 energy use and w/CHP, Fractionation, 

Membrane Separation, and Raw Starch Hydrolysis 

(wet DGS). 

318 Dry Mill corn ethanol plant using coal with 

2022 energy use and dry DDGS. 

319 Dry Mill corn ethanol plant using biomass 

with 2022 energy use and dry DDGS. 

the baseline transportation fuel used in 

2005 in the U.S. as mandated by EISA. 

The percent reduction goal is the 

lifecycle GHG emissions of the biofuel 

compared to the baseline petroleum fuel 

it is replacing. 

TABLE VI.C.2–1—PAYBACK PERIOD

[in years] 

Fuel type 

Payback period (years) 

Reduction 

goal: 0% 

Reduction 

goal: 20% 

Reduction 

goal: 50% 

Reduction 

goal: 60% 

Corn Ethanol 2022 Base Dry Mill NG 315 ........................................................ 33 54 316 N/A N/A 

Corn Ethanol 2022 Best Case Dry Mill NG 317 ............................................... 23 31 N/A N/A 

Corn Ethanol 2022 Base Dry Mill Coal 318 ...................................................... 75 >100 N/A N/A 

Corn Ethanol 2022 Base Dry Mill Biomass 319 ................................................ 22 31 N/A N/A 

Soybean Biodiesel ........................................................................................... 32 46 105 N/A 

Waste Grease Biodiesel .................................................................................. 0 0 0 N/A 

Sugarcane Ethanol .......................................................................................... 18 26 61 N/A 

Switchgrass Ethanol ........................................................................................ 3 3 4 5 

Corn Stover Ethanol ........................................................................................ 0 0 0 0 

As described in Section VI.B.5, we 

have focused our lifecycle GHG analysis 

on two ways of accounting for GHG 

emissions over time. In one set of results 

we consider lifecycle GHG emissions 

over 100 years and discount future 

emissions with a 2% discount rate. In 

the other set of results we consider 30 

years of GHG emissions with no 

discounting of future emissions (i.e., 0% 

discount rate). Whereas the discussion 

immediately above focused on lifecycle 

GHG impacts assuming 100 years with 

a 2% discount rate and 30 years with no 

discount rate, Table VI.C.2–2 shows the 

lifecycle GHG emissions reductions 

estimates with a variety of time periods 

and discount rates. 

TABLE VI.C.2–2—LIFECYCLE GHG EMISSIONS CHANGES OF SELECT BIOFUELS RELATIVE TO THE 2005 PETROLEUM

BASELINE

Lifecycle GHG emissions changes of select biofuels relative to the 2005 petroleum baseline 

Time horizon 30 Years 50 Years 100 Years 

Discount rate 0% 2% 3% 7% 0% 2% 3% 7% 0% 2% 3% 7% 

Corn Ethanol 

Dry Mill NG 5% 18% 25% 54% ¥17% ¥2% 7% 44% ¥36% ¥16% ¥4% 41% 

Corn Ethanol 

Best Case Dry Mill NG ¥14% ¥1% 6% 35% ¥36% ¥21% ¥12% 25% ¥55% ¥35% ¥23% 22% 

Corn Ethanol 

Dry Mill Coal 34% 46% 53% 83% 11% 27% 35% 72% ¥8% 13% 24% 69% 

Corn Ethanol 

Dry Mill Biomass ¥18% ¥6% 1% 31% ¥41% ¥25% ¥17% 20% ¥60% ¥39% ¥28% 16% 

Soybean Biodiesel .................... 4% 20% 29% 68% ¥24% ¥4% 7% 55% ¥48% ¥22% ¥7% 51% 

Waste Grease Biodiesel ........... ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% ¥80% 

Sugarcane Ethanol .................... ¥27% ¥17% ¥11% 12% ¥45% ¥32% ¥26% 3% ¥61% ¥44% ¥35% 1% 

Switchgrass Ethanol .................. ¥124% ¥122% ¥121% ¥115% ¥128% ¥125% ¥124% ¥117% ¥131% ¥128% ¥126% ¥117% 

Corn Stover Ethanol .................. ¥116% ¥117% ¥117% ¥118% ¥115% ¥116% ¥116% ¥117% ¥114% ¥115% ¥115% ¥117% 

D. Thresholds 

EISA established GHG thresholds for 

each category of renewable fuel that it 

mandates. EISA also provided EPA with 

the authority to adjust the threshold 

levels for each category of renewable 

fuels if certain requirements are met. 

Renewable fuels must achieve a 20% 

reduction in lifecycle greenhouse gas 

emissions compared to the average 

lifecycle greenhouse gas emissions for 

gasoline or diesel sold or distributed as 

transportation fuel in 2005. Due to the 

grandfathering provisions of EISA as 

adopted in this rule, this threshold only 

pertains to renewable fuel produced at 

plants to be constructed in the future. 

EPA is permitted to adjust this 

threshold to as low as 10%, based on 

the ‘‘maximum achievable level, taking 

cost into consideration, for natural gas 

fired corn-based ethanol plants allowing 

for the use of a variety of technologies.’’ 

Based on our analysis, there are a 

number of corn ethanol natural gas 

plant configurations that could meet the 

20% reduction in GHG emissions 

thresholds in 2022 if modeling emission 

over a 100 year time frame and then 

discounting these emissions 2%. 

Therefore, based on this assessment, we 

believe that an adjustment to the 20% 

threshold would be unnecessary and we 

are proposing to maintain it at the 20% 

level if we adopt the 100 year, 2% 

discounting methodology. 

On the other hand, based on our 

current analyses, if we adopt an 

assessment methodology which assesses 

emissions over just 30 years, then no 

currently analyzed natural gas-fired 

corn ethanol pathway will meet the 

20% threshold. However, some of the 

natural gas corn ethanol pathways do 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25049 

have lifecycle GHG emission benefits in 

the 10% to 20% range. Corn ethanol is 

expected to be the major biofuel 

contributing to meeting the renewable 

fuel standards through at least the 

middle of the next decade. Therefore, if 

we adopt a 30 year timeframe for 

emissions assessment and do not 

discount the results, we may adjust the 

renewable fuel thresholds to the 

minimum level as necessary to 

incorporate at least a few of the best 

GHG pathways for corn ethanol. While 

this adjusted threshold level could be 

revised based on pathway analyses done 

for the final rule, at this time we would 

intend to allow a full 10% adjustment 

of the renewable fuel threshold, down to 

a threshold value of 10% reduction 

compared to the 2005 gasoline baseline. 

Cellulosic biofuels must meet a 60% 

reduction in GHG emissions relative to 

the petroleum baseline. EPA is 

permitted to adjust this threshold to as 

low as 50% if it is ‘‘not commercially 

feasible for fuels made using a variety of 

feedstocks, technologies, and processes’’ 

to achieve the 60% threshold. Our 

initial analysis indicates that cellulosic 

biofuels from corn stover, switchgrass, 

and bagasse will all meet the 60% 

threshold regardless of whether we use 

to 100 year, 2% discount methodology 

or the 30 year analysis time frame 

without discounting. Furthermore, we 

believe most fuels made from other 

cellulosic feedstocks would as well. 

Therefore we do not believe it is 

necessary to adjust the threshold for 

cellulosic biofuel at this time. 

Biomass-based diesel must achieve a 

50% reduction in GHG emissions 

relative to petroleum-based diesel. EPA 

is permitted to adjust this threshold to 

as low as 40% if it is ‘‘not commercially 

feasible for fuels made using a variety of 

feedstocks, technologies, and processes’’ 

to meet the 50% level. For biomassbased diesel, our analysis indicates that 

biodiesel from waste oils such as yellow 

grease and tallow would meet the 50% 

threshold, and we anticipate that 

biodiesel from chicken waste and nonfood grade corn oil fractionation would 

as well regardless of whether we use a 

100 year, 2% discount methodology or 

the 30 year analysis time frame without 

discounting. However, our current 

analysis indicates that there is 

insufficient feedstock from waste grease 

and fats to meet the one billion gallon 

volumetric requirement under EISA. 

Biodiesel from soy oil (and we believe 

biodiesel from other food grade 

vegetable oils) would reduce GHG 

emissions by no more than 22% using 

a 100 year, 2% discount methodology 

and would be estimated to increase 

GHG emissions if we analyze emission 

impacts over 30 years whether the 

emissions are discounted or not. Even if 

EPA adjusted the biomass-based diesel 

standard to the minimum allowable 

level of 40%, soybean-based biodiesel 

would still not meet the GHG emissions 

reductions threshold for biomass based 

diesel fuel. One option for meeting the 

volumetric requirement and the 

emissions reduction threshold, 

assuming a 100 year timeframe and a 

2% discount rate for GHG emission 

impacts would be to allow biodiesel 

producers to average the emissions 

reductions from a blend of soy oil or 

food grade vegetable oil-based biodiesel 

with waste oil based biodiesel, as 

discussed in more detail in Section VI.E. 

However, this approach may still be 

insufficient to ensure that the required 

volumes of biomass-based diesel can be 

produced unless other sources of 

biomass-based diesel become available. 

Therefore, we invite comments on 

whether it be appropriate to both reduce 

the threshold to 40% and allow 

biodiesel producers to average their 

emissions to meet the one billion gallon 

volumetric requirement as discussed 

below in Section VI.E.3.c. 

Advanced biofuels must achieve a 

50% reduction in GHG emissions. EPA 

is permitted to adjust this threshold to 

as low as 40% if it is ‘‘not commercially 

feasible for fuels made using a variety of 

feedstocks, technologies, and processes’’ 

to achieve the 50% threshold. Our 

current lifecycle analysis suggests that 

sugarcane based ethanol only offers an 

estimated 44% reduction in GHG 

emissions relative to the gasoline it 

replaces when assessing 100 years of 

emission impacts and discounting these 

emissions 2%, and an estimated 27% 

reduction when assessing 30 years of 

emission impacts with no discounting. 

Therefore, it would not qualify as an 

advanced biofuel if we did not adjust 

the 50% GHG threshold. We are also 

unaware of other renewable fuels that 

may be available in sufficient volumes 

over the next several years to allow the 

statutory volume requirements for 

advanced biofuel to be met. As a result, 

we are proposing that the GHG 

threshold for advanced biofuels be 

adjusted to 44% or potentially as low as 

40% depending on the results from the 

analyses that will be conducted for the 

final rule. Based on our current analysis 

of the lifecycle GHG impacts of 

sugarcane ethanol, such an adjustment 

would help ensure that the volume 

mandates for advanced biofuel can be 

met. 

We invite comments on these 

proposed thresholds and our basis for 

them. 

E. Assignment of Pathways to 

Renewable Fuel Categories 

The lifecycle analyses that we 

conducted for a variety of fuel pathways 

formed the basis for our determination 

of which pathways would be permitted 

to generate RINs, and to which of the 

four renewable fuel categories 

(cellulosic biofuel, biomass-based 

diesel, advanced biofuel, and renewable 

fuel) those RINs should be assigned. 

This determination involved comparing 

the lifecycle GHG performance 

estimates to the GHG thresholds 

associated with each renewable fuel 

category, discussed in Section VI.D 

above. In addition, each of the four 

renewable fuel categories is defined in 

EISA to include or exclude certain types 

of feedstocks and production processes, 

and these definitions also played a role 

in determining the appropriate category 

for each pathway. This section describes 

our proposed assignments of pathways 

to one of the four renewable fuel 

categories. The GHG lifecycle values 

used in this assignment of fuel 

pathways to the four renewable fuel 

categories were based on the lifecycle 

analysis results over a 100-year 

timeframe and using a 2% discount rate, 

as described in Section VI.C. Different 

assignments of pathways to the four 

renewable fuel categories would occur 

with different lifecycle results, but we 

propose that the same assignment 

methodology would be followed 

regardless. 

1. Statutory Requirements 

EISA establishes requirements that are 

common to all four categories of 

renewable fuel in addition to 

requirements that are unique to each of 

the four categories. The common 

requirements determine which fuels are 

valid for generating RINs under the 

RFS2 program. For instance, all 

renewable fuel must be made from 

renewable biomass, which defines the 

types of feedstocks that can be used to 

produce renewable fuel that is valid 

under the RFS2 program, and also 

defines the types of land on which crops 

can be grown if those crops are used to 

produce valid renewable fuel under the 

RFS2 program. See Section III.B.4 for a 

more detailed discussion of renewable 

biomass. Moreover, all renewable fuel 

must displace fossil fuel present in 

transportation fuel, or be used as home 

heating oil or jet fuel. 

The requirements that are unique to 

each of the four categories provide a 

basis for assigning each pathway to a 

category. For each of the four categories 

of renewable fuel, EISA provides a 

definition, specifies the associated GHG 

25050 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

thresholds, lists the allowable 

feedstocks and/or fuel types, and in 

some cases provides exclusions. Table 

VI.E.1–1 summarizes these requirements 

as we are applying them under the 

proposed RFS2 program. 

TABLE VI.E.1–1—REQUIREMENTS FOR RENEWABLE FUEL CATEGORIES

Cellulosic biofuel Biomass-based diesel Advanced biofuel Renewable fuel 

GHG threshold ............... 60% ................................ 50% a .............................. 40–44% a ........................................ 20% a, b. 

Eligible Inclusions .......... Renewable fuel made 

from cellulose, hemicellulose, or lignin.

Any renewable fuel that 

is a diesel fuel substitute.

All cellulosic biofuel and biomassbased diesel, as well as other 

renewable fuels including ethanol from sugar, starch, or 

waste materials, biogas, and butanol and other alcohols.

All advanced biofuel, 

and any other fuel 

made from renewable 

biomass that is used 

to replace or reduce 

the quantity of fossil 

fuel present in a transportation fuel. 

Exclusions ...................... ........................................ Any renewable fuel 

made from coprocessing with petroleum.

Ethanol derived from corn starch.

aAs discussed in Section VI.D, we are seeking comment on the need to adjust the thresholds, and are proposing that the GHG threshold for 

advanced biofuels be adjusted to as low as 40%. b 20% threshold does not apply to grandfathered volumes. See discussion in Section III.B.3. 

2. Assignments for Pathways Subjected 

to Lifecycle Analyses 

There are a wide variety of pathways 

(unique combinations of feedstock, fuel 

type, and fuel production process) that 

could result in renewable fuel that 

would be valid under the RFS2 

program. As described earlier in this 

section, we conducted lifecycle analyses 

for some of these pathways, and these 

analyses allowed us to determine if the 

GHG thresholds shown in Table 

VI.E.1–1 would be met under the 

assumption of a 100-year timeframe and 

discount rate of 2%. For other pathways 

that we have not yet subjected to 

lifecycle analyses, there were some 

cases in which we could nevertheless 

still make moderately confident 

determinations as to the likely GHG 

impacts by making comparisons to the 

pathways that we did analyze. A 

discussion of these other determinations 

is provided in Section VI.E.3 below. 

For pathways that we subjected to 

lifecycle analysis, we were able to 

assign each pathway to one of the four 

renewable fuel categories defined in 

EISA by comparing the descriptions of 

each pathway and its associated GHG 

performance to the requirements shown 

in Table VI.E.1–1. The results are shown 

in Table VI.E.2–1. 

TABLE VI.E.2–1—PROPOSED ASSIGNMENT OF PATHWAYS TO ONE OF THE FOUR RENEWABLE FUEL CATEGORIES FOR

PATHWAYS SUBJECTED TO LIFECYCLE ANALYSES

Cellulosic biofuel pathways ................................. Ethanol produced from corn stover or switchgrass in a process that uses enzymes to hydrolyze the cellulose and hemicellulose. 

Biomass-based diesel pathways ......................... Biodiesel (mono alkyl esters) produced from waste grease and waste oils. 

Advanced biofuel pathways ................................ Ethanol produced from sugarcane sugar in a process that uses sugarcane bagasse for process heat. a

Renewable fuel pathways ................................... Ethanol produced from corn starch in a process that uses biomass for process heat. 

Ethanol produced from corn starch in a process that includes: 

—Dry mill plant. 

—Process heat derived from natural gas. 

—Combined heat and power (CHP). 

—Fractionation of feedstocks. 

—All distillers grains are dried. 

Ethanol produced from corn starch in a process that includes: 

—Dry mill plant. 

—Process heat derived from natural gas. 

—All distillers grains are wet. 

Ethanol produced from corn starch in a process that includes: 

—Dry mill plant. 

—Process heat derived from coal. 

—Combined heat and power (CHP). 

—Fractionation of feedstocks. 

—Membrane separation of ethanol. 

—Raw starch hydrolysis. 

—All distillers grains are dried. 

Ethanol produced from corn starch in a process that includes: 

—Dry mill plant. 

—Process heat derived from coal. 

—Combined heat and power (CHP). 

—Fractionation of feedstocks. 

—Membrane separation of ethanol. 

—All distillers grains are wet. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25051 

TABLE VI.E.2–1—PROPOSED ASSIGNMENT OF PATHWAYS TO ONE OF THE FOUR RENEWABLE FUEL CATEGORIES FOR

PATHWAYS SUBJECTED TO LIFECYCLE ANALYSES—Continued 

Biodiesel (mono alkyl esters) produced from soybean oil. 

aOur current analysis concludes that ethanol from sugarcane sugar would have a GHG performance of 44% in comparison to gasoline under 

our assumed 100-year timeframe and 2% discount rate. Since this falls short of the 50% GHG threshold for advanced biofuel, we have categorized it as general renewable fuel. However, we request comment on lowering the applicable GHG threshold for advanced biofuel so that ethanol from sugarcane sugar could be categorized as advanced biofuel. See further discussion in Section VI.D. 

In addition, our lifecycle analyses also 

identified pathways that did not meet 

the minimum 20% GHG threshold 

under an assumed 100-year timeframe 

and 2% discount rate, and thus would 

be prohibited from generating RINs 

unless a facility met the prerequisites 

for grandfathering as described in 

Section III.B.3. These prohibited 

pathways all involved the production of 

ethanol from corn starch in a process 

that uses natural gas or coal for process 

heat, but which does not meet any of the 

process technology requirements listed 

in Table VI.E.2–1. Our proposal for 

temporary D codes in § 80.1416 would 

explicitly prohibit the generation of 

RINs for these pathways. 

The proposed assignments of 

individual pathways to one of the four 

renewable fuel categories shown in the 

table above assumed a 100-year 

timeframe and discount rate of 2% for 

lifecycle GHG emission impacts. The 

assignments would be different if we 

had assumed a different timeframe and 

discount rate. By comparing the relative 

GHG emission reductions shown in 

Table VI.C.1–2 to the thresholds in 

Table VI.E.1–1, a variety of different 

assignments is possible covering 

timeframes of 30, 50, and 100 years, and 

discount rates of 0%, 2%, 3%, and 7%. 

For instance, under the assumption of 

30 years and no discounting, 

switchgrass ethanol and corn stover 

ethanol would continue to be 

categorized as cellulosic biofuel and 

biodiesel made from waste grease would 

continue to be categorized as biomassbased diesel. However, sugarcane 

ethanol could no longer be potentially 

categorized as advanced biofuel but 

instead would be categorized as 

renewable fuel. Moreover, some 

pathways would not meet the minimum 

threshold of 20% for renewable fuel, 

and so could not generate RINs if the 

volume was not grandfathered. This 

would include soybean biodiesel and all 

of the corn starch ethanol pathways 

shown in Table VI.E.2–1 produced from 

newly constructed plants not meeting 

the grandfathering criteria discussed in 

Section III.B.3. 

3. Assignments for Additional Pathways 

We were not able to conduct lifecycle 

modeling for all potential pathways in 

time for this proposed rulemaking. 

Instead, we focused the lifecycle GHG 

emissions analysis on the feedstocks 

that, based on FASOM predictions and 

other information, we anticipate could 

contribute the largest volumes to the 

renewable fuel pool and the production 

processes representing the largest shares 

of the market. As more information 

becomes available, we anticipate that 

we will be updating the lifecycle 

methodology and expanding the list of 

emission factors. 

Beyond the pathways that we 

explicitly subjected to lifecycle analysis, 

there are additional pathways that may 

not currently be significant contributors 

to the volume of renewable fuel 

produced, but their volumes could 

increase in the future. Moreover, we 

believe it is important that as many 

pathways as possible be included in the 

lookup table in the regulations to help 

ensure that the volume requirements in 

EISA can be met and to encourage the 

development of new fuels. To this end, 

we evaluated these additional pathways 

to determine if they could be deemed 

valid for generation of RINs, and if so 

which of the four renewable fuel 

categories they would fall into. This 

section describes our evaluation of these 

additional pathways and the resulting 

proposed assignment to one or more of 

the four renewable fuel categories. 

a. Ethanol From Starch 

Our lifecycle analysis focused on 

ethanol from corn starch. However, 

there are a variety of other sources of 

starch that use or could use a very 

similar process for conversion to 

ethanol. These include wheat, barley, 

oats, rice, and sorghum. Some existing 

corn-ethanol facilities already use small 

amounts of starch from these other 

plants along with corn in their 

production of ethanol. 

Although we have not explicitly 

analyzed the land use or processing 

impacts of these other starch plants on 

their lifecycle GHG performance, we 

believe it would be reasonable to 

assume similar impacts to corn in terms 

of the types of land that would be 

displaced and other aspects of 

producing and transporting the 

feedstock. Therefore, we propose that 

the pathways shown in Table VI.E.2–1 

for ethanol produced from corn starch 

also be applied to ethanol produced 

from other sources of starch. 

The lifecycle analyses conducted for 

this proposal only examined cases in 

which a corn-ethanol facility dried 

100% of its distiller’s grains or left 

100% of its distiller’s grains wet. The 

treatment of the distiller’s grains for 

corn-ethanol facilities impacts the 

determination of whether the 20% GHG 

threshold for renewable fuel has been 

met. However, in practice some 

facilities may dry only a portion of their 

distiller’s grains and leave the 

remainder wet. As described in Section 

III.D.3, we are proposing that a facility 

that dried only a portion of its distiller’s 

grain would be treated as if it dried 

100% of its grains, and would thus need 

to implement additional GHG-reducing 

technologies as described in the lookup 

table in order to qualify to generate 

RINs. However, we are also taking 

comment on whether a selection of 

pathways should be included in the 

lookup table that represent corn-ethanol 

facilities that dry only a portion of their 

distiller’s grains. We also request 

comment on whether RINs could be 

assigned to only a portion of the 

facility’s ethanol in cases wherein only 

a portion of the distiller’s grains are 

dried. 

b. Renewable Fuels from Cellulosic 

Biomass 

In analyzing the lifecycle GHG 

impacts of cellulosic ethanol, we 

determined that ethanol produced from 

corn stover or switchgrass through a 

process using enzymatic hydrolysis 

followed by fermentation of the 

resulting sugars met the GHG threshold 

of 60% for cellulosic biofuel by a wide 

margin (regardless of the discount rate 

and the time period over which the 

lifecycle GHG emissions are 

discounted). However, there are many 

other potential sources of cellulosic 

biomass, and other processing 

mechanisms to convert cellulosic 

biomass into fuel. For some of these 

cases, we believe that we can make 

determinations regarding whether the 

GHG thresholds shown in Table VI.E.1– 

1 are likely to be met. In addition, as the 

forestry component of the FASOM 

model is incorporated into the analysis, 

25052 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

we will analyze pathways using planted 

trees, tree residue, and slash and precommercial thinnings from forestland, 

as qualify under the renewable biomass 

definition, for feedstock. 

Cellulosic biomass sources include 

waste biomass such as corn stover, and 

crops grown specifically for fuel 

production such as switchgrass. While 

cellulosic crops grown for the purpose 

of fuel production could have land use 

implications in a lifecycle GHG 

analysis, waste materials produced 

during the harvesting of some other type 

of crop would not. Given that the GHG 

impacts of a fermentation-based fuel 

production process are likely to be very 

similar for cellulose from a variety of 

feedstocks, we believe it would be 

reasonable to conclude that any 

cellulosic feedstock from a waste source 

that is subjected to enzymatic 

hydrolysis followed by fermentation of 

the resulting sugars would be very likely 

to meet the 60% GHG threshold for 

cellulosic biofuel. Therefore, we 

propose that cellulosic ethanol 

produced through an enzymatic 

hydrolysis process followed by 

fermentation using any eligible waste 

cellulosic feedstock would be 

determined to meet the 60% GHG 

threshold for cellulosic biofuel. This 

would include such wastes as wheat 

straw, rice straw, sugarcane bagasse, 

forest slash and thinnings, and yard 

waste. 

As stated earlier, cellulosic crops 

grown for the purpose of fuel 

production could have land use 

implications in a lifecycle GHG 

analysis. However, the only cellulosic 

crop that we subjected to lifecycle 

analysis was switchgrass which had a 

relatively small impact of land-use. 

Other cellulosic crops that have been 

considered for fuel production include 

miscanthus and trees such as poplar and 

willow. It is possible that the land use 

impacts of miscanthus and planted trees 

could be different from that for 

switchgrass. For instance, while 

switchgrass can be grown on marginal 

lands, planted trees may require more 

arable land to thrive. However, 

according to our lifecycle analysis for 

switchgrass, the land use impacts could 

significantly increase and the 60% 

threshold for cellulosic biofuel would 

still be met. Therefore, we propose that 

the pathways shown in Table VI.E.2–1 

for ethanol produced from switchgrass 

through an enzymatic hydrolysis 

process followed by fermentation also 

be applied to ethanol produced from 

miscanthus and planted trees. We 

intend to examine this pathway more 

closely for the final rule to determine if 

this categorization is appropriate, and 

request comment on the land use 

impacts of miscanthus and planted 

trees. 

Renewable fuels can also be produced 

from cellulosic biomass through various 

thermochemical processes rather than 

enzymatic hydrolysis followed by 

fermentation. One example of such 

thermochemical processes would be 

biomass gasification to produce 

‘‘syngas’’ (a mixture of hydrogen and 

carbon monoxide) which is then 

catalytically synthesized through a 

Fischer-Tropsch process to produce 

ethanol, diesel, gasoline, or other 

transportation fuels. Another example 

would be a catalytic depolymerization 

process in which the biomass is first 

catalytically cracked to smaller 

molecules and then polymerized under 

specific combinations of temperature, 

pressure, and residence time to produce 

a transportation fuel. We have not 

conducted a lifecycle analysis of these 

pathways, but we believe that we can 

nonetheless make a reasonable 

determination regarding the appropriate 

renewable fuel category. For instance, 

we would expect that the GHG 

emissions produced during fuel 

production would be higher for a 

thermochemical process than for 

enzymatic hydrolysis due to the need 

for greater process heat produced 

through the combustion of fossil fuels. 

However, the yield of fuel produced per 

ton of biomass is likely to be greater for 

thermochemical processing due to the 

conversion of the lignin to fuel in 

addition to the cellulose and 

hemicellulose. Thus, while the lifecycle 

GHG analyses we conducted for corn 

stover and switchgrass demonstrated 

that the 60% GHG threshold for 

cellulosic biofuel would be met by a 

wide margin, this margin may be 

smaller if a thermochemical process was 

used. While we intend to conduct 

further analyses of this family of 

pathways for the final rule, we believe 

that a change from enzymatic hydrolysis 

to a thermochemical process would be 

expected to meet the 60% GHG 

threshold associated with cellulosic 

biofuel. Therefore, we propose that the 

use of corn stover or other waste 

cellulosic biomass, switchgrass, or 

planted trees in a thermochemical 

process would qualify as cellulosic 

biofuel under the RFS2 program. This 

would include pathways that produce 

ethanol, cellulosic diesel, or cellulosic 

gasoline. Since cellulosic diesel fuel 

produced in this way would also meet 

the requirements for biomass-based 

diesel, we propose to allow it to be 

categorized as either cellulosic biofuel 

or biomass-based diesel at the 

producer’s discretion. See further 

discussion of this issue in Section 

III.D.2.a. We request comment on our 

proposed assignment of categories for 

renewable fuels produced through a 

thermochemical process, as well as data 

and other information relating to the 

various types of thermochemical fuel 

production processes. 

c. Biodiesel 

Our lifecycle analysis of biodiesel 

(mono alkyl esters) produced from 

waste greases/oils demonstrated that the 

50% GHG threshold for biomass-based 

diesel would be met. Much of the GHG 

benefit of these waste greases/oils 

derives from the fact that they have no 

land use impacts. While we did not 

subject corn oil that is non-food grade 

to lifecycle analysis, it is likely that it 

would also have no land use impacts. 

Moreover, such non-food grade corn oil 

would require nearly the same process 

energy to convert it into biodiesel. 

Therefore, we propose that the pathway 

shown in Table VI.E.2–1 for biodiesel 

produced from waste greases/oils also 

be applied to biodiesel produced from 

non-food grade corn oil. We intend to 

analyze this pathway in more depth for 

the final rule. 

Our lifecycle analysis of biodiesel 

produced from soybean oil may also be 

applicable to biodiesel produced from 

other types of virgin (not waste) oils. 

This would include canola oil, rapeseed 

oil, sunflower oil, and peanut oil. While 

we have not conducted a detailed 

assessment of the land use impacts of 

these other virgin oils, it is possible that 

they would meet the 20% threshold for 

generic renewable fuel. Therefore, we 

propose that the pathway shown in 

Table VI.E.2–1 for biodiesel produced 

from soybean oil also be applied to 

biodiesel produced from other these 

virgin oils. We request comment on 

whether this is appropriate. 

Although our proposed list of RINgenerating pathways would allow 

biodiesel made from waste greases/oils 

to qualify as biomass-based diesel, it is 

likely that there would be insufficient 

quantities of these feedstocks to reach 

the 1.0 billion gallon requirement by 

2012. Biodiesel produced from soybean 

oil would not qualify as biomass-based 

diesel, but instead would be categorized 

as generic renewable fuel based on our 

current analysis of its lifecycle GHG 

performance. However, biodiesel 

production facilities can process either 

soybean oil or waste grease with 

relatively minor changes in operations, 

and many facilities that formerly used 

soybean oil have recently switched to 

waste grease due to its more favorable 

economics. Since the GHG performance 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25053 

of biodiesel made from waste greases/ 

oils met the 50% GHG threshold by a 

wide margin, and since it is common 

industry practice for biodiesel facilities 

to use these two feedstock sources, we 

believe it may be appropriate to allow 

a biodiesel production facility to 

average the GHG benefit generated 

through the use of waste grease with the 

lower GHG performance of biodiesel 

produced from soybean oil at the same 

facility. 

We recognize that an approach in 

which we allow a biodiesel production 

facility to average the GHG benefit of 

waste grease with that from soybean oil 

raises questions about whether similar 

averaging could be allowed for other 

combinations of feedstocks, other types 

of fuel, or across multiple facilities 

within the same company. While we 

believe that the circumstances 

surrounding biodiesel production are 

somewhat unique—two different 

feedstocks subjected to essentially the 

same production process in a single 

facility—we nevertheless request 

comment on the appropriateness of such 

an averaging approach for biodiesel. 

Based on our lifecycle analyses, 

biodiesel produced from waste grease 

has a GHG performance of 80% 

reduction from the conventional diesel 

baseline, while biodiesel produced from 

soybean oil has a GHG performance of 

22% reduction. In order to meet the 

GHG threshold of 50% for biomassbased diesel, a biodiesel production 

facility would need to use a minimum 

of 48% waste grease and a maximum of 

52% soybean oil. Thus, a pathway that 

would allow a biodiesel production 

facility to designate all of its biodiesel 

as biomass-based diesel would include 

a requirement that the producer 

demonstrate that every batch has been 

produced from no less than 48% waste 

grease and no more than 52% soybean 

oil. 

Although this approach would allow 

the total volume of biomass-based diesel 

to be larger than if waste greases/oils 

alone qualified, it is still possible than 

the 1.0 billion gallon requirement would 

not be met due to limits on the 

availability of waste greases and oils. 

For instance, we estimate that the total 

volume of waste greases and oils may be 

no larger than 0.3–0.4 billion gallons. As 

a result, we request comment on 

whether it would also be appropriate to 

lower the GHG threshold for biomassbased diesel. If this GHG threshold were 

lowered to 40%, a biodiesel production 

facility would only need to use a 

minimum of 31% waste greases/oils 

instead of 48%. 

We recognize that it may be difficult 

for a biodiesel production facility to 

process a consistent mixture of waste 

grease and soybean oil every day. 

Therefore, we request comment on 

alternative approaches. For instance, if 

a biodiesel production facility processed 

only waste grease for the first 175 days 

(48% × 365 days) of a calendar year, we 

could allow it to designate any biodiesel 

produced from soybean oil for the 

remainder of the year as biomass-based 

diesel. However, this may be difficult 

for some producers who must contend 

with cold temperature storage and 

blending issues in the early part of a 

calendar year by processing only 

soybean oil. Alternatively, we could 

allow a company to average the 

production at all of its facilities, where 

one facility processed only waste grease 

and another processed only soybean oil. 

Finally, we request comment on an 

alternative approach in which an 

obligated party, rather than the biodiesel 

production facility, would demonstrate 

that a minimum number of waste 

grease-based biodiesel RINs is used to 

meet the biomass-based diesel standard 

in comparison to the number of soybean 

oil-based biodiesel RINs. In essence, the 

averaging would be carried out by the 

obligated party instead of the biodiesel 

producer. In this approach, biodiesel 

RINs would not be placed into biomassbased diesel category shown in Table 

VI.E.1–1, but instead would be placed 

into two separate categories as waste 

grease RINs or soybean oil RINs. This 

designation would require that the list 

of applicable D codes for use in the RIN 

be expanded from four to six as shown 

in Table VI.E.3.c–1. 

TABLE VI.E.3.C–1—ALTERNATIVE APPROACH TO D CODES FOR AVERAGING WASTE GREASE AND SOYBEAN OIL BIODIESEL RINS IN COMPLIANCE

D 

value Proposal meaning Alternative approach meaning 

1 ...... Cellulosic biofuel Cellulosic biofuel 

2 ...... Biomass-based 

diesel.

Biomass-based 

diesel 

3 ...... Advanced biofuel Biodiesel made 

from soybean 

oil 

4 ...... Renewable fuel ... Biodiesel made 

from waste 

grease 

5 ...... (Not applicable) .. Advanced biofuel 

6 ...... (Not applicable) .. Renewable fuel 

Since other types of renewable fuel 

may still qualify as biomass-based 

diesel, we would retain a separate D 

code for this category under this 

approach. This could allow biodiesel 

producers who choose the process a 

minimum of 48% waste greases/oils 

each day to continue to assign a D code 

of 2 to their biodiesel. 

An obligated party could use any 

combination of RINs with a D code of 

2, 3, or 4 in order to comply with the 

biomass-based diesel standard. 

However, he would also be subject to an 

additional requirement that the ratio of 

D=3 RINs to D=4 RINs must be less than 

1.08. This criterion would ensure that a 

minimum of 47 RINs representing 

biodiesel from waste grease would be 

used for compliance purposes for every 

53 RINs representing biodiesel from 

soybean oil that are also used for 

compliance. 

We request comment on these 

alternative approaches to the treatment 

of biodiesel. 

d. Renewable Diesel Through 

Hydrotreating 

We did not conduct a lifecycle 

analysis for the production of non-ester 

renewable diesel through a 

hydrotreating process. However, we 

believe that our analysis of biodiesel 

provides sufficient information to allow 

us to designate the renewable fuel 

category for various pathways leading to 

the production of renewable diesel. 

Renewable diesel is generally made 

from the same feedstocks as biodiesel, 

namely soybean oil, waste greases/oils, 

tallow, and chicken fat. Therefore, the 

GHG impacts associated with 

producing/collecting the feedstock and 

transporting it to the production facility 

would be the same regardless of 

whether the final product is biodiesel or 

renewable diesel. 

The fossil energy requirements of the 

production process contribute a 

relatively small amount to the overall 

GHG performance for biodiesel. For 

example, the 50% GHG threshold would 

still be met for biodiesel produced from 

waste grease even if the fossil energy 

requirements doubled. As a result, 

compared to the transesterification 

process used to produce biodiesel, any 

small variations in fossil energy 

requirements for renewable diesel 

production in a hydrotreater would be 

unlikely to change compliance with the 

broad categories created by the GHG 

thresholds for biomass-based diesel and 

generic renewable fuel. Therefore, we 

believe that it would be appropriate to 

assign applicable renewable fuel 

categories to renewable diesel pathways 

in parallel with the assignments we are 

proposing for biodiesel, including the 

potential for averaging of soyoil and 

waste grease derived volumes. 

Renewable diesel produced from waste 

grease, tallow, or chicken fat in a 

hydrotreater that does not coprocess 

petroleum feedstocks would be 

25054 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

categorized as biomass-based diesel. 

Renewable diesel produced from waste 

grease, tallow, or chicken fat in a 

hydrotreater that does coprocess 

petroleum feedstocks would be 

categorized as advanced biofuel. 

Finally, renewable diesel produced from 

soybean oil in a hydrotreater would be 

categorized as generic renewable fuel. 

4. Summary 

Based on the discussion above, we 

have identified 15 pathways that we 

propose could be used to produce fuel 

that would meet the volume 

requirements in EISA assuming a 100 

year analysis time frame and 

discounting GHG emissions over time 

by 2%. As noted above, these pathways 

would be adjusted should we adopt 

other time frames or discount rates 

(including a zero discount rate) for the 

final rule. Each pathway would be 

assigned a D code for use in generating 

RINs that corresponds to one of the four 

renewable fuel categories. Our proposed 

list of allowable pathways is shown in 

Table VI.E.4–1. 

TABLE VI.E.4–1—APPLICABLE CATEGORIES FOR EACH FUEL PATHWAY a

Fuel type Feedstock Production process requirements Category 

Ethanol ........................................... Starch from corn, wheat, barley, 

oats, rice, or sorghum.

—Process heat derived from biomass.Renewable fuel. 

Ethanol ........................................... Starch from corn, wheat, barley, 

oats, rice, or sorghum.

—Dry mill plant ............................. Renewable fuel. 

—Process heat derived from natural gas.

—Combined heat and power 

(CHP).

—Fractionation of feedstocks.

—Some or all distillers grains are 

dried.

Ethanol ........................................... Starch from corn, wheat, barley, 

oats, rice, or sorghum.

—Dry mill plant ............................. Renewable fuel. 

—Process heat derived from natural gas.

—All distillers grains are wet.

Ethanol ........................................... Starch from corn, wheat, barley, 

oats, rice, or sorghum.

—Dry mill plant ............................. Renewable fuel. 

—Process heat derived from coal.

—Combined heat and power 

(CHP).

—Fractionation of feedstocks.

—Membrane separation of ethanol.

—Raw starch hydrolysis.

—Some or all distillers grains are 

dried.

Ethanol ........................................... Starch from corn, wheat, barley, 

oats, rice, or sorghum.

—Dry mill plant ............................. Renewable fuel. 

—Process heat derived from coal.

—Combined heat and power 

(CHP).

—Fractionation of feedstocks.

—Membrane separation of ethanol.

—All distillers grains are wet.

Ethanol ........................................... Cellulose and hemicellulose from 

corn stover, switchgrass, 

miscanthus, wheat straw, rice 

straw, sugarcane bagasse, forest waste, yard waste, or planted trees.

—Enzymatic hydrolysis of cellulose.Cellulosic biofuel. 

—Fermentation of sugars.

—Process heat derived from 

lignin.

Ethanol ........................................... Cellulose and hemicellulose from 

corn stover, switchgrass, 

miscanthus, wheat straw, rice 

straw, sugarcane bagasse, forest waste, yard waste, or planted trees.

—Thermochemical gasification of 

biomass.

Cellulosic biofuel. 

—Fischer-Tropsch process.

Ethanol ........................................... Sugarcane sugar .......................... —Process heat derived from sugarcane bagasse.Advanced biofuel. 

Biodiesel (mono alkyl ester) .......... Waste grease, waste oils, tallow, 

chicken fat, or non-food grade 

corn oil.

—Transesterification ..................... Biomass-based diesel. 

Biodiesel (mono alkyl ester) .......... Soybean oil and other virgin plant 

oils.

—Transesterification ..................... Renewable fuel. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25055 

TABLE VI.E.4–1—APPLICABLE CATEGORIES FOR EACH FUEL PATHWAY a—Continued 

Fuel type Feedstock Production process requirements Category 

Cellulosic diesel ............................. Cellulose and hemicellulose from 

corn stover, switchgrass, 

miscanthus, wheat straw, rice 

straw, sugarcane bagasse, forest waste, yard waste, or planted trees.

—Thermochemical gasification of 

biomass.

Cellulosic biofuel or biomassbased diesel. 

—Fischer-Tropsch process.

—Catalytic depolymerization.

Non-ester renewable diesel ........... Waste grease, waste oils, tallow, 

chicken fat, or corn oil.

—Hydrotreating.

—Dedicated facility that processes only renewable biomass.Biomass-based diesel. 

Non-ester renewable diesel ........... Waste grease, waste oils, tallow, 

chicken fat, or non-food grade 

corn oil.

—Hydrotreating ............................. Advanced biofuel. 

—Coprocessing facility that also 

processes petroleum feedstocks.

Non-ester renewable diesel ........... Soybean oil and other virgin plant 

oils.

—Hydrotreating ............................. Renewable fuel. 

Cellulosic gasoline ......................... Cellulose and hemicellulose from 

corn stover, switchgrass, 

miscanthus, wheat straw, rice 

straw, sugarcane bagasse, forest waste, yard waste, or planted trees.

—Thermochemical gasification of 

biomass.

Cellulosic biofuel. 

—Fischer-Tropsch process.

—Catalytic depolymerization.

a Under our assumed 100-year timeframe and 2% discount rate. 

As stated earlier, there may be other 

potential pathways that could lead to 

qualifying renewable fuel. While we do 

not have sufficient information at this 

time to evaluate the likely lifecycle GHG 

impact and thus assign those pathways 

to one of the four renewable fuel 

categories, we do plan on doing these 

evaluations for the final rule. Pathways 

that we intend to subject to lifecycle 

analysis include butanol from starches 

or oils and renewable diesel from 

biomass using pyrolysis or catalytic 

reforming. We request comment on the 

inputs necessary to apply lifecycle 

analysis to these pathways. We also 

request comment on other pathways 

that should be analyzed and the data 

that would be necessary for those 

analyses. 

For pathways that are not included in 

the lookup table in the final rule, we are 

also proposing a regulatory mechanism 

whereby a producer could temporarily 

assign their renewable fuel to one of the 

four renewable fuel categories under 

certain conditions. For further 

discussion of this issue, see Section 

III.D.5. 

F. Total GHG Emission Reductions 

Our analysis of the overall GHG 

emission impacts of this proposed 

rulemaking was performed in parallel 

with the lifecycle analysis performed to 

develop the individual fuel thresholds 

described in previous sections. The 

same system boundaries apply such that 

this analysis includes the effects of three 

main areas: (a) emissions related to the 

production of biofuels, including the 

growing of feedstock (corn, soybeans, 

etc.) with associated domestic and 

international land use change impacts, 

transport of feedstock to fuel production 

plants, fuel production, and distribution 

of finished fuel; (b) emissions related to 

the extraction, production and 

distribution of petroleum gasoline and 

diesel fuel that is replaced by use of 

biofuels; and (c) difference in tailpipe 

combustion of the renewable and 

petroleum based fuels. As discussed in 

the previous sections we will be 

updating our lifecycle approach for the 

final rule and there are some areas that 

we were not able to quantify at this 

time, such as secondary impacts in the 

energy sector. We are working to 

include this for our final rule analysis. 

Consistent with the fuel volume 

feasibility analysis and criteria pollutant 

emissions, our analysis of the GHG 

impacts of increased renewable fuel use 

was conducted by comparing the 

impacts of the 2022 36 Bgal of 

renewable fuel volumes required by 

EISA to a projected 2022 reference case 

of approximately 14 Bgal of renewable 

fuel volumes. Similar to what was done 

to calculate lifecycle thresholds for 

individual fuels we considered the 

change in 2022 of these two volume 

scenarios of renewable fuels to 

determine overall GHG impacts of the 

rule. The reference case for the GHG 

emission comparisons was taken from 

the AEO 2007 projected renewable fuel 

production levels for 2022 prior to 

enactment of EISA. This scenario 

provided a point of comparison for 

assessing the impacts of the RFS2 

standard volumes on GHG emissions. 

We ran these multi-fuel scenarios 

through our FASOM and FAPRI models 

and applied the Winrock land use 

change assumptions to determine to 

overall GHG impacts. We were only able 

to analyze 2022 reference and control 

cases. However, in reality the impacts of 

corn ethanol and soybean biodiesel will 

be experienced beginning in 2009, with 

the impacts of cellulosic ethanol and 

sugarcane ethanol growing in later years 

as their volumes increase. 

The main difference between this 

overall impacts analysis and the 

analysis conducted to develop the 

threshold values for the individual fuels 

is that we analyzed the total change in 

renewable fuels in one scenario as 

opposed to looking at individual fuel 

impacts. When analyzing the impact of 

the total 36 billion gallons of renewable 

fuel, we also took into account the 

agricultural sector interactions 

necessary to produce the full 

complement of feedstock. We also 

25056 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

considered a mix of plant types and 

configurations for the 2022 renewable 

fuel production representing the mix of 

plants we project to be in operation in 

2022. This is based on the same analysis 

used in the plant location and fuel 

feasibility analysis described in Section 

V.B. 

For this overall impacts analysis we 

used a different petroleum baseline fuel 

that is offset from renewable fuel use. 

The lifecycle threshold values are 

required by EISA to be based on a 2005 

petroleum fuel baseline. For this 

inventory analysis of the overall impacts 

of the rule we considered the crude oil 

and finished product that would be 

replaced in 2022. Displaced petroleum 

product analysis was consistent with 

work performed for the energy security 

analysis described in Section IX.B. For 

this analysis we consider that 25% of 

displaced gasoline will be imported 

gasoline. For the domestic production 

we assumed replacement of the 2022 

crude mix which is projected to include 

7.6% tar sands and 3.8% Venezuelan 

heavy crude which is higher then the 

projected mix in 2005 which includes 

5% tar sands and 1% Venezuelan heavy 

crude. 

Given these many differences, simply 

adding up the individual lifecycle 

results determined in Section VI.C. 

multiplied by their respective volumes 

would yield a different assessment of 

the overall rule impacts. The two 

analyses are separate in that the overall 

rule impacts capture interactions 

between the different fuels that can not 

be broken out into per fuels impacts, 

while the threshold values represent 

impacts of specific fuels but do not 

account for all the interactions. 

For example, when we consider the 

combined impact of the different fuel 

volumes when analyzed separately, the 

overall land use change is 9.0 million 

acres. However, when we analyze the 

volume changes all together, the overall 

land use change is approximately 10% 

higher. 

The primary reason for the difference 

in acre change between the sum of the 

individual fuel scenarios and the 

combined fuel scenarios is that when 

looking at individual fuels there is some 

interaction between different crops (e.g., 

corn replacing soybeans), but with 

combined volume scenario when all 

mandates need to be met there is less 

opportunity for crop replacement (e.g., 

both corn and soybean acres needed) 

and therefore more land is required. 

Important findings of our analysis 

include: 

• As with the threshold lifecycle 

calculations, assumptions about timing 

to consider impacts over and discount 

rates will have a significant impact on 

results. 

• We estimate the largest overall 

agricultural sector impact is an increase 

in land use change impacts, reflecting 

the shift of crop production 

internationally to meet the biofuel 

demand in the U.S. Increased crop 

production internationally resulted in 

land use change emissions associated 

with converting land into crop 

production. 

• Our analysis indicates that overall 

domestic agriculture emissions would 

increase. There is a relatively small 

increase in total domestic crop acres 

however, there are additional inputs 

required due to the removal of crop 

residues. The assumption is that 

removal will require more inputs to 

make up for lost residue nutrients. 

These additional inputs result in GHG 

emissions from production and from 

N2O releases from application. This 

effect is somewhat offset by reductions 

due to lower livestock production. 

These results are dependent on our 

agricultural sector input and emission 

assumptions that are being updated for 

the final rule (e.g., N2O emission factor 

work). 

• In particular due to this 

international impact, the potential 

overall GHG emission reductions of 

biofuels produced from food crops such 

as corn ethanol and soy biodiesel are 

significantly impacted. Large near term 

emission increases due to land use 

change require a number of years before 

the emission reductions due to corn 

ethanol and soy biodiesel use will offset 

the near term emission increase as 

discussed in the threshold calculation 

section. 

• Cellulosic biofuels contribute by far 

the most to the total emission 

reductions due to both their superior 

per gallon emission reductions and the 

large volume of these fuels anticipated 

to be used by 2022. 

The timing of the impact of land use 

change and ongoing renewable fuels 

benefits were discussed in the previous 

lifecycle fuel threshold section. The 

issue is slightly different for this 

analysis since we are considering 

absolute tons of emissions and not 

determining a threshold comparison to 

petroleum fuels. However the results 

can be presented in a similar manner to 

our individual fuels analysis in that we 

can determine net benefits over time 

with different discount rates and over a 

different time frame for consideration. 

As discussed in previous sections on 

lifecycle GHG thresholds there is an 

initial one time release from land 

conversion and smaller ongoing releases 

but there are also ongoing benefits of 

using renewable fuels over time 

replacing petroleum fuel use. Based on 

the volume scenario considered, the one 

time land use change impacts result in 

448 million metric tons of CO2–eq. 

emissions increase. There are, however, 

based on the biofuel use replacing 

petroleum fuels, GHG reductions in 

each year. When modeling the program 

as if all fuel volume changes occur in 

2022, and considering 100 years of 

emission impacts that are discounted by 

2% per year, we get an estimated total 

discounted NPV reduction in GHG 

emissions of 6.8 billion tons over 100 

years. Totaling the emissions impacts 

over 30 years but assuming a 0% 

discount rate over this 30 year period 

would result in an estimated total NPV 

reduction in GHG emissions of 4.5 

billion tons over 30 years. 

This total NPV reduction can be 

converted into annual average GHG 

reductions, which can be used for the 

calculations of the monetized GHG 

benefits as shown in Section IX.C.4. 

This annualized value is based on 

converting the lump sum present values 

described above into their annualized 

equivalents. For this analysis we 

convert the NPV results for the 100 year 

2% discount rate into an annualized 

average such that the NPV of the 

annualized average emissions will equal 

the NPV of the actual emission stream 

over 100 years with a 2% discount rate. 

This results in an annualized average 

emission reduction of approximately160 

million metric tons of CO2–eq. 

emissions. A comparable value 

assuming 30 years of GHG emissions 

changes but not applying a discount rate 

to those emissions results in an 

estimated annualized average emission 

reduction of approximately 150 million 

metrics tons of CO2–eq. emissions. 

G. Effects of GHG Emission Reductions 

and Changes in Global Temperature 

and Sea Level 

1. Introduction 

The reductions in CO2 and other 

GHGs associated with the proposal will 

affect climate change projections. 

Because GHGs mix well in the 

atmosphere and have long atmospheric 

lifetimes, changes in GHG emissions 

will affect future climate for decades to 

centuries. One common indicator of 

climate change is global mean surface 

temperature and sea level rise. This 

section estimates the response in global 

mean surface temperature projections to 

the estimated net global GHG emissions 

reductions associated with the proposed 

rulemaking (See Section VI.F for the 

estimated net reductions in global 

emissions over time by GHG). 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25057 

320MiniCAM is a long-term, global integrated 

assessment model of energy, economy, agriculture 

and land use, that considers the sources of 

emissions of a suite of greenhouse gases (GHG’s), 

emitted in 14 globally disaggregated global regions 

(i.e., U.S., Western Europe, China), the fate of 

emissions to the atmosphere, and the consequences 

of changing concentrations of greenhouse related 

gases for climate change. MiniCAM begins with a 

representation of demographic and economic 

developments in each region and combines these 

with assumptions about technology development to 

describe an internally consistent representation of 

energy, agriculture, land-use, and economic 

developments that in turn shape global emissions. 

Brenkert A, S. Smith, S. Kim, and H. Pitcher, 2003: 

Model Documentation for the MiniCAM. PNNL– 

14337, Pacific Northwest National Laboratory, 

Richland, Washington. For a recent report and 

detailed description and discussion of MiniCAM, 

see Clarke, L., J. Edmonds, H. Jacoby, H. Pitcher, J. 

Reilly, R. Richels, 2007. Scenarios of Greenhouse 

Gas Emissions and Atmospheric Concentrations. 

Sub-report 2.1A of Synthesis and Assessment 

Product 2.1 by the U.S. Climate Change Science 

Program and the Subcommittee on Global Change 

Research. Department of Energy, Office of 

Biological & Environmental Research, Washington, 

DC., USA, 154 pp. 

321MAGICC consists of a suite of coupled gascycle, climate and ice-melt models integrated into 

a single framework. The framework allows the user 

to determine changes in GHG concentrations, 

global-mean surface air temperature and sea-level 

resulting from anthropogenic emissions of carbon 

dioxide (CO2), methane (CH4), nitrous oxide (N2O), 

reactive gases (e.g., CO, NOX, VOCs), the 

halocarbons (e.g. HCFCs, HFCs, PFCs) and sulfur 

dioxide (SO2). MAGICC emulates the global-mean 

temperature responses of more sophisticated 

coupled Atmosphere/Ocean General Circulation 

Models (AOGCMs) with high accuracy. Wigley, 

T.M.L. and Raper, S.C.B. 1992. Implications for 

Climate and Sea-Level of Revised IPCC Emissions 

Scenarios Nature 357, 293–300. Raper, S.C.B., 

Wigley T.M.L. and Warrick R.A. 1996. in Sea-Level 

Rise and Coastal Subsidence: Causes, Consequences 

and Strategies J.D. Milliman, B.U. Haq, Eds., Kluwer 

Academic Publishers, Dordrecht, The Netherlands, 

pp. 11–45. Wigley, T.M.L. and Raper, S.C.B. 2002. 

Reasons for larger warming projections in the IPCC 

Third Assessment Report J. Climate 15, 2945–2952. 

322Clarke et al., 2007. 

323 In IPCC reports, equilibrium climate 

sensitivity refers to the equilibrium change in the 

annual mean global surface temperature following 

a doubling of the atmospheric equivalent carbon 

dioxide concentration. The IPCC states that climate 

sensitivity is ‘‘likely’’ to be in the range of 2 °C to 

4.5 °C and described 3 °C as a ‘‘best estimate.’’ The 

IPCC goes on to note that climate sensitivity is 

‘‘very unlikely’’ to be less than 1.5 °C and ‘‘values 

substantially higher than 4.5 °C cannot be 

excluded.’’ IPCC WGI, 2007, Climate Change 

2007—The Physical Science Basis, Contribution of 

Working Group I to the Fourth Assessment Report 

of the IPCC, http://www.ipcc.ch/. 

324 IPCC WGI, 2007. The baseline increases by 

2100 from our MiniCAM–MAGICC runs are 2 °C to 

5 °C for global mean surface temperature and 35 to 

74 centimeters for global mean sea level. 

325 ‘‘Because understanding of some important 

effects driving sea level rise is too limited, this 

report does not assess the likelihood, nor provide 

a best estimate or an upper bound for sea level 

rise.’’ IPCC Synthesis Report, p. 45 

2. Estimated Projected Reductions in 

Global Mean Surface Temperatures 

EPA estimated changes in projected 

global mean surface temperatures to 

2100 using the MiniCAM (Mini Climate 

Assessment Model) integrated 

assessment model 320 coupled with the 

MAGICC (Model for the Assessment of 

Greenhouse-gas Induced Climate 

Change) simple climate model.321

MiniCAM was used to create the 

globally and temporally consistent set of 

climate relevant variables required for 

running MAGICC. MAGICC was then 

used to estimate the change in the global 

mean surface temperature over time. 

Given the magnitude of the estimated 

emissions reductions associated with 

the proposed rule, a simple climate 

model such as MAGICC is reasonable 

for estimating the climate response. 

EPA applied the estimated annual 

GHG emissions changes for the proposal 

to the MiniCAM U.S. Climate Change 

Science Program (CCSP) Synthesis and 

Assessment Product baseline 

emissions.322 Specifically, the CO2, 

N2O, and CH4 annual emission changes 

from 2022–2121 from Section VI.F were 

applied as net reductions to the 

MiniCAM CCSP global baseline net 

emissions for each GHG. Post-2121, we 

assumed no change in emissions from 

the baseline. This assumption is more 

conservative than allowing the 

emissions reductions to continue. 

Table VI.G.2 provides our estimated 

reductions in projected global mean 

surface temperatures and sea level 

associated with the proposed increase in 

renewable fuels in 2022. To capture 

some of the uncertainty in the climate 

system, we estimated the changes in 

projected temperatures and sea level 

across the most current 

Intergovernmental Panel on Climate 

Change (IPCC) range of climate 

sensitivities, 1.5 °C to 6.0 °C.323 To 

illustrate the time profile of the 

estimated reductions in projected global 

mean surface temperatures and sea 

level, we have also provided Figures 

VI.G.2–1 and VI.G.2–2. 

TABLE VI.G.2–1—ESTIMATED REDUCTIONS IN PROJECTED GLOBAL MEAN SURFACE TEMPERATURE AND GLOBAL MEAN

SEA LEVEL FROM BASELINE IN 2030, 2050, 2100, AND 2200 FOR THE PROPOSED STANDARD IN 2022 

Climate sensitivity 

1.5 2 3 4.5 6 

Change in global mean surface temperatures (degrees Celsius) 

2030 ......................................................................................................... 0.000 0.000 ¥0.001 ¥0.001 ¥0.001 

2050 ......................................................................................................... ¥0.001 ¥0.002 ¥0.002 ¥0.002 ¥0.003 

2100 ......................................................................................................... ¥0.003 ¥0.004 ¥0.005 ¥0.006 ¥0.007 

2200 ......................................................................................................... ¥0.003 ¥0.004 ¥0.006 ¥0.008 ¥0.009 

Change in global mean sea level rise (centimeters) 

2030 ......................................................................................................... ¥0.002 ¥0.002 ¥0.003 ¥0.003 ¥0.003 

2050 ......................................................................................................... ¥0.012 ¥0.014 ¥0.017 ¥0.020 ¥0.022 

2100 ......................................................................................................... ¥0.045 ¥0.052 ¥0.063 ¥0.074 ¥0.082 

2200 ......................................................................................................... ¥0.077 ¥0.091 ¥0.114 ¥0.143 ¥0.172 

The results in Table VI.G.2–1 and 

Figures VI.G.2–1 and VI.G.2–2 show 

small, but detectable, reductions in the 

global mean surface temperature and sea 

level rise projections across all climate 

sensitivities. Overall, the reductions are 

small relative to the IPCC’s ‘‘best 

estimate’’ temperature increases by 2100 

of 1.8 °C to 4.0 °C.324 Although IPCC 

does not issue ‘‘best estimate’’ sea level 

rise projections, the model-based range 

across SRES scenarios is 18 to 59 cm by 

2099.325 Both figures illustrate that the 

overall emissions reductions can 

decrease projected annual temperature 

and sea level for all climate sensitivities. 

This means that the distribution of 

potential temperatures in any particular 

year is shifting down. However, the shift 

is not uniform. The magnitude of the 

decrease is larger for higher climate 

25058 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

326 In 2100, the reduction in projected sea level 

rise for climate sensitivities of 3 and 6 is 

approximately 40% and 80% greater than the 

reduction for a climate sensitivity of 1.5. This 

difference grows over time, to approximately 50% 

and 120% by 2200. 

327For global average temperature after 2100, the 

growth in the size of the decrease noticeable slows. 

This is because the emissions changes associated 

with the policy were only estimated for 100 years. 

Note that even with emissions reductions stopping 

after 100 years, there continues to be a decrease in 

projected temperatures due to reduced inertia in the 

climate system from the earlier emissions 

reductions. However, unlike temperature, after 

2100, the size of the decrease in sea level rise 

increases as the projected reduction in warming has 

a continued effect on ice melt and ocean thermal 

expansion. 

sensitivities. Thus, the probability of a 

higher temperature or sea level in any 

year is lowered more than the 

probability of a lower temperature or sea 

level. For instance, in 2100, the 

reduction in projected temperature for 

climate sensitivities of 3 and 6 is 

approximately 65% and 140% greater 

than the reduction for a climate 

sensitivity of 1.5. This difference grows 

over time, to approximately 80% and 

185% by 2200. The same pattern 

appears in the reductions in the sea 

level rise projections.326 Also 

noteworthy in Figures VI.G.2–1 and 

VI.G.2–2 is that the size of the decreases 

grows over time due to the cumulative 

effect of a lower stock of GHGs in the 

atmosphere (i.e., concentrations).327

The bottom line is that the risk of 

climate change is being lowered, as the 

probabilities of any level of temperature 

increase and sea level rise are reduced 

and the probabilities of the largest 

temperature increases and sea level rise 

are reduced even more. For the Final 

Rulemaking, we hope to more explicitly 

estimate the shapes of the distributions 

and the estimated shifts in the shapes in 

response to the Rulemakings. 

BILLING CODE 6560–50–P 


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Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25059 

328NOX and VOC are precursors to the criteria 

pollutant ozone; we group them with criteria 

pollutants in this chapter for ease of discussion. 

329For this analysis these RFS1 base and 

mandated ethanol levels were assumed constant to 

2022. 

BILLING CODE 6560–50–C 

VII. How Would the Proposal Impact 

Criteria and Toxic Pollutant Emissions 

and Their Associated Effects? 

A. Overview of Impacts 

Today’s proposal would influence the 

emissions of ‘‘criteria’’ pollutants (those 

pollutants for which a National Ambient 

Air Quality Standard has been 

established), criteria pollutant 

precursors,328 and air toxics, which may 

affect overall air quality and health. 

Emissions would be affected by the 

processes required to produce and 

distribute large volumes of biofuels 

proposed in today’s action and the 

direct effects of these fuels on vehicle 

and equipment emissions. As detailed 

in Chapter 3 of the Draft Regulatory 

Impact Analysis (DRIA), we have 

estimated emissions impacts of 

production and distribution-related 

emissions using the life cycle analysis 

methodology described in Section VI 

with emission factors for criteria and 

toxic emissions for each stage of the life 

cycle, including agriculture, feedstock 

transportation, and the production and 

distribution of biofuel; included in this 

analysis are the impacts of reduced 

gasoline and diesel refining as these 

fuels are displaced by biofuels. 

Emission impacts of tailpipe and 

evaporative emissions for on and off 

road sources have been estimated by 

incorporating ‘‘per vehicle’’ fuel effects 

from recent research into mobile source 

emission inventory estimation methods. 

For today’s proposal we are 

presenting two sets of emission impacts 

meant to present a range of the possible 

effects of ethanol blends on light-duty 

vehicle emissions. This approach is 

carried forward from analysis 

supporting the first RFS rule, which 

presented ‘‘primary’’ and ‘‘sensitivity’’ 

fuel effects cases differentiated by E10 

effects on cars and trucks. For this 

analysis we also analyze two fuel effects 

scenarios, now termed ‘‘less sensitive’’ 

and ‘‘more sensitive,’’ referring to the 

sensitivity of car and truck exhaust 

emissions to both E10 and E85 blends. 

As detailed in Section VII.C, the ‘‘less 

sensitive’’ case does not apply any E10 

effects to NOx or HC emissions for later 

model year vehicles, or E85 effects for 

any pollutant, while the ‘‘more 

sensitive’’ case assumes that later model 

year vehicles have lower fuel sensitivity 

than earlier model vehicles. EPA and 

other parties are in the midst of 

gathering additional data to help clarify 

emissions impacts of ethanol on lightduty vehicles, and should be able to 

reflect the new data for the final rule. 

Analysis of criteria and toxic emission 

impacts was performed for calendar 

year 2022, since this year reflects the 

full implementation of today’s proposal. 

Our 2022 projections account for 

projected growth in vehicle travel and 

the effects of applicable emission and 

fuel economy standards, including Tier 

2 and Mobile Source Air Toxics (MSAT) 

rules for cars and light trucks and 

recently finalized controls on sparkignited off-road engines. The impacts 

were analyzed relative to three different 

reference case ethanol volumes, ranging 

from 3.64 to 13.2 billion gallons per 

year, in order to understand the impacts 

of today’s proposal in different contexts. 

To assess the total impact of the RFS 

program, emissions were analyzed 

relative to the RFS1 rule base case of 

3.64 billion gallons in 2004. To assess 

the impact of today’s proposal relative 

to the current mandated volumes, we 

analyzed impacts relative to RFS1 

mandate of 7.5 billion gallons of 

renewable fuel use by 2012, which was 

estimated to include 6.7 billion gallons 

of ethanol.329 In order to assess the 

impact of today’s proposal relative to 

the level of ethanol projected to already 

be in place by 2022, the AEO2007 

projection of 13.2 billion gallons of 


EP26MY09.010</GPH>
25060 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

ethanol in 2022 was analyzed. For this 

analysis our modeling was based on the 

differences between the AEO2007 

reference case and the control case; to 

generate impacts for the RFS1 base and 

mandated volumes we simply scaled the 

modeled AEO2007-based impacts up 

according to the larger increases in 

renewable fuel volumes relative to the 

other reference cases. For the final rule 

we plan to directly model the RFS1 

mandate reference case as well as the 

AEO2007 case. 

For the proposal we have only 

estimated the change in national 

emission totals that would result from 

today’s proposal. These totals may not 

be a good indication of local or regional 

air quality and health impacts. These 

results are aggregated across highly 

localized sources, such as emissions 

from ethanol plants and evaporative 

emissions from cars, and reflect offsets 

such as decreased emissions from 

gasoline refineries. The location and 

composition of emissions from these 

disparate sources may strongly 

influence the air quality and health 

impacts of today’s proposed action, and 

full-scale photochemical air quality 

modeling is necessary to accurately 

assess this. These localized impacts will 

be assessed in the final rule as discussed 

in Section VII.D. 

Our projected emission impacts for 

the ‘‘less sensitive’’ and ‘‘more 

sensitive’’ cases are shown in Table 

VII.A–1 and VII.A–2 for 2022. Shown 

relative to each reference case are the 

expected emission changes for the U.S. 

in that year, and the percent 

contribution of this impact relative to 

the total U.S. inventory. Overall we 

project the proposed program will result 

in significant increases in ethanol and 

acetaldehyde emissions—increasing the 

total U.S. inventories of these pollutants 

by 30–40% in 2022 relative to the RFS1 

mandate case. We project more modest 

increases in NOx, HC, PM, SO2, 

formaldehyde, and acrolein relative to 

the RFS1 mandate case. We project a 

decrease in ammonia (NH3) emissions 

due to reductions in livestock 

agricultural activity, CO (due to impacts 

of ethanol on exhaust emissions from 

vehicles and nonroad equipment), and 

benzene (due to displacement of 

gasoline with ethanol in the fuel pool). 

As shown, the direction of changes for 

1,3-butadiene and naphthalene depends 

on whether it is the ‘‘less sensitive’’ or 

‘‘more sensitive’’ case. 

TABLE VII.A–1—RFS2 ‘‘LESS SENSITIVE’’ CASE EMISSION IMPACTS IN 2022 RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

NOx .......................................................... 312,400 2.8 274,982 2.5 195,735 1.7 

HC ............................................................ 112,401 1.0 72,362 0.6 ¥8,193 ¥0.07 

PM10 ......................................................... 50,305 1.4 37,147 1.0 9,276 0.3 

PM2.5 ........................................................ 14,321 0.4 11,452 0.3 5,376 0.16 

CO ............................................................ ¥2,344,646 ¥4.4 ¥1,669,872 ¥3.1 ¥240,943 ¥0.4 

Benzene ................................................... ¥2,791 ¥1.7 ¥2,507 ¥1.5 ¥1,894 ¥1.1 

Ethanol ..................................................... 210,680 36.5 169,929 29.4 83,761 14.5 

1,3-Butadiene ........................................... 344 2.9 255 2.1 65 0.5 

Acetaldehyde ........................................... 12,516 33.7 10,369 27.9 5,822 15.7 

Formaldehyde .......................................... 1,647 2.3 1,348 1.9 714 1.0 

Naphthalene ............................................. 5 0.03 3 0.02 ¥1 ¥0.01 

Acrolein .................................................... 290 5.0 252 4.4 174 3.0 

SO2 ........................................................... 28,770 0.3 4,461 0.05 ¥47,030 ¥0.5 

NH3 ........................................................... ¥27,161 ¥0.6 ¥27,161 ¥0.6 ¥27,161 ¥0.6 

TABLE VII.A–2—RFS2 ‘‘MORE SENSITIVE’’ CASE EMISSION IMPACTS IN 2022 RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 Mandate AEO2007 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

NOx .......................................................... 402,795 3.6 341,028 3.0 210,217 1.9 

HC ............................................................ 100,313 0.9 63,530 0.6 ¥15,948 ¥0.14 

PM10 ......................................................... 46,193 1.3 33,035 0.9 5,164 0.15 

PM2.5 ........................................................ 10,535 0.3 7,666 0.2 1,589 0.05 

CO ............................................................ ¥3,779,572 ¥7.0 ¥3,104,798 ¥5.8 ¥1,675,869 ¥3.1 

Benzene ................................................... ¥5,962 ¥3.5 ¥5,494 ¥3.3 ¥4,489 ¥2.7 

Ethanol ..................................................... 228,563 39.6 187,926 32.5 105,264 18.2 

1,3-Butadiene ........................................... ¥212 ¥1.8 ¥282 ¥2.4 ¥430 ¥3.6 

Acetaldehyde ........................................... 16,375 44.0 14,278 38.4 9,839 26.5 

Formaldehyde .......................................... 3,373 4.7 3,124 4.3 2,596 3.6 

Naphthalene ............................................. ¥175 ¥1.2 ¥178 ¥1.3 ¥187 ¥1.3 

Acrolein .................................................... 253 4.4 218 3.8 143 2.5 

SO2 ........................................................... 28,770 0.3 4,461 0.05 ¥47,030 ¥0.5 

NH3 ........................................................... ¥27,161 ¥0.6 ¥27,161 ¥0.6 ¥27,161 ¥0.6 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25061 

The breakdown of these results by the 

fuel production/distribution (‘‘well-topump’’ emissions) and vehicle and 

equipment (‘‘pump-to-wheel’’) 

emissions is discussed in the following 

sections. 

B. Fuel Production & Distribution 

Impacts of the Proposed Program 

Fuel production and distribution 

emission impacts of the proposed 

program were estimated in conjunction 

with the development of life cycle GHG 

emission impacts and the GHG emission 

inventories discussed in Section VI. 

These emissions are calculated 

according to the breakdowns of 

agriculture, feedstock transport, fuel 

production, and fuel distribution; the 

basic calculation is a function of fuel 

volumes in the analysis year and the 

emission factors associated with each 

process or subprocess. Additionally, the 

emission impact of displaced petroleum 

is estimated, using the same domestic/ 

import shares discussed in Section VI 

above. 

In general the basis for this life cycle 

evaluation was the analysis conducted 

as part of the Renewable Fuel Standard 

(RFS1) rulemaking, but enhanced 

significantly. While our approach for 

the RFS1 was to rely heavily on the 

‘‘Greenhouse Gases, Regulated 

Emissions, and Energy Use in 

Transportation’’ (GREET) model, 

developed by the Department of 

Energy’s Argonne National Laboratory 

(ANL), we are now able to take 

advantage of additional information and 

models to significantly strengthen and 

expand our analysis for this proposed 

rule. In particular, the modeling of the 

agriculture sector was greatly expanded 

beyond the RFS1 analysis, employing 

economic and agriculture models to 

consider factors such as land-use 

impact, agricultural burning, fertilizer, 

pesticide use, livestock, crop allocation, 

and crop exports. 

Other updates and enhancements to 

the GREET model assumptions include 

updated feedstock energy requirements 

and estimates of excess electricity 

available for sale from new cellulosic 

ethanol plants, based on modeling by 

the National Renewable Energy 

Laboratory (NREL). EPA also updated 

the fuel and feedstock transport 

emission factors to account for recent 

EPA emission standards and modeling, 

such as the diesel truck standards 

published in 2001 and the locomotive 

and commercial marine standards 

finalized in 2008. Emission factors for 

new corn ethanol plants continue to use 

the values developed for the RFS1 rule, 

which were based on data submitted by 

states for dry mill plants. There are no 

new standards planned at this time that 

would offer any additional control of 

emissions from corn or cellulosic 

ethanol plants. In addition, GREET does 

not include air toxics or ethanol. Thus 

emission factors for ethanol and the 

following air toxics were added: 

benzene, 1,3-butadiene, formaldehyde, 

acetaldehyde, acrolein and naphthalene. 

Results of these calculations relative 

to each of the reference cases for 2022 

are shown in Table VII.B–1 for the 

criteria pollutants, ammonia, ethanol 

and individual air toxic pollutants. It 

should be noted that the impacts 

relative to the two RFS1 reference cases 

(3.64 and 6.7 billion gallons) rely on 

applying ethanol volume proportions to 

the modeling results of the AEO2007 

reference case (13.2 billion gallons). Due 

to the complex interactions involved in 

projections in the agricultural modeling, 

we did not attempt to adjust the 

agricultural inputs of the AEO reference 

case for the other two reference cases. 

So the fertilizer and pesticide quantities, 

livestock counts, and total agricultural 

acres were the same for all three 

reference cases. The agricultural 

modeling that had been done for the 

RFS1 rule itself was much simpler and 

inconsistent with the new modeling, so 

it would be inappropriate to use those 

estimates. Thus, we plan to conduct 

additional agricultural modeling 

specifically for the RFS1 mandate case 

prior to finalizing this rule. 

The fuel production and distribution 

impacts of the proposed program on 

VOC are mainly due to increases in 

emissions connected with biofuel 

production, countered by decreases in 

emissions associated with gasoline 

production and distribution as ethanol 

displaces some of the gasoline. Increases 

in NOX, PM2.5, and SOX are driven by 

combustion emissions from the 

substantial increase in corn and 

cellulosic ethanol production. Ethanol 

plants (corn and cellulosic) tend to have 

greater combustion emissions relative to 

petroleum refineries on a per-BTU of 

fuel produced basis. Increases in SOX

emissions are primarily due to corn 

ethanol production. Ammonia 

emissions are expected to decrease 

substantially due to lower livestock 

counts, which more than offsets 

increased ammonia from fertilizer use. 

Ethanol vapor and most air toxic 

emissions associated with fuel 

production and distribution are 

projected to increase. Relative to the 

U.S. total reference case emissions with 

RFS1 mandate ethanol volumes, 

increases of 10–20% for acetaldehyde 

and ethanol vapor are especially 

significant because they are driven 

directly by the increased ethanol 

production and distribution. 

Formaldehyde and acrolein increases 

are smaller, on the order of 1–5%. 

Benzene emissions are estimated to 

decrease by 1% due to decreased 

gasoline production. There are also very 

small increases in 1,3-butadiene and 

decreases in naphthalene relative to the 

U.S. total emissions. 

TABLE VII.B–1—FUEL PRODUCTION AND DISTRIBUTION IMPACTS IN 2022 RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual 

short tons 

Percent of 

total U.S. 

inventory 

Annual 

short tons 

Percent of 

total U.S. 

inventory 

Annual 

short tons 

Percent of 

total U.S. 

inventory 

NOX ............................................................................ 241,041 2 .1 222,732 2 .0 183,951 1 .6 

HC .............................................................................. 77,295 0 .7 46,702 0 .4 ¥17,501 ¥0 .2 

PM10 ........................................................................... 50,482 1 .4 37,324 1 .1 9,453 0 .3 

PM2.5 .......................................................................... 14,419 0 .4 11,550 0 .3 5,473 0 .16 

CO .............................................................................. 186,559 0 .3 179,855 0 .3 165,656 ¥0 .5 

Benzene ..................................................................... ¥1,670 ¥1 .0 ¥1,686 ¥1 .0 ¥1,719 ¥1 .0 

Ethanol ....................................................................... 115,187 19 .9 100,134 17 .3 68,379 11 .8 

1,3-Butadiene ............................................................. 16 0 .13 16 0 .14 17 0 .14 

Acetaldehyde ............................................................. 7,460 20 .1 6,680 18 .0 5,029 13 .5 

Formaldehyde ............................................................ 877 1 .2 800 1 .1 638 0 .9 

Naphthalene ............................................................... ¥6 ¥0 .04 ¥5 ¥0 .04 ¥4 ¥0 .03 

Acrolein ...................................................................... 278 4 .8 244 4 .2 174 3 .0 

25062 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

330The impact of renewable diesel was not 

estimated for the proposal; we expect little overall 

impact on criteria and toxic emissions due to the 

relatively small volume change, and because 

emission effects relative to conventional diesel are 

presumed to be negligible. 

TABLE VII.B–1—FUEL PRODUCTION AND DISTRIBUTION IMPACTS IN 2022 RELATIVE TO EACH REFERENCE CASE— 

Continued 

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual 

short tons 

Percent of 

total U.S. 

inventory 

Annual 

short tons 

Percent of 

total U.S. 

inventory 

Annual 

short tons 

Percent of 

total U.S. 

inventory 

SO2 ............................................................................. 28,770 0 .3 4,461 0 .05 ¥47,030 ¥0 .5 

NH3 ............................................................................. ¥27,161 ¥0 .6 ¥27,161 ¥0 .6 ¥27,161 ¥0 .6 

C. Vehicle and Equipment Emission 

Impacts of Fuel Program 

The effects of the fuel program on 

vehicle and equipment emissions are a 

direct function of the effects of these 

fuels on exhaust and evaporative 

emissions from vehicles and off-road 

equipment, and evaporation of fuel from 

portable containers. To assess these 

impacts we conducted separate analyses 

to quantify the emission impacts of 

additional E10 due to today’s proposal 

on gasoline vehicles, nonroad sparkignited engines and portable fuel 

containers; E85 on cars and light trucks; 

biodiesel on diesel vehicles; and 

increased refueling events due to lower 

energy density of biofuels.330

For the proposal we have analyzed 

inventory impacts for two fuel effects 

scenarios to attempt to bound the 

potential impacts on ethanol on 

gasoline-fueled vehicle exhaust 

emissions: 

(1) ‘‘Less Sensitive’’: No exhaust VOC 

or NOX emission impact on Tier 1 and 

later vehicles due to E10, and no impact 

due to E85. This was termed the 

‘‘primary’’ case in the RFS1 rule. 

(2) ‘‘More Sensitive’’: VOC and NOX

emission impacts due to E10 based on 

limited test data from newer technology 

vehicles that were analyzed as part of 

the RFS1 rule. This data showed a 7% 

reduction in exhaust VOC emissions 

and an 8% increase in per-vehicle NOX

emissions for Tier 1 and later vehicles 

using E10 relative to E0. The E10 effects 

are consistent with the ‘‘sensitivity’’ 

case from the RFS1 rule. For RFS2 this 

case also includes E85 effects reflecting 

significant increases in acetaldehyde, 

formaldehyde and ethanol emissions, 

and reductions in PM and CO. 

EPA and other parties are in the midst 

of gathering additional data on the 

emission impacts of ethanol fuels on 

later model vehicles, which we plan to 

consider in updating our final rule 

analysis. 

We have also estimated the E10 

effects on permeation emissions from 

light-duty vehicles based on testing 

previously completed by the 

Coordinating Research Council (CRC). 

Nonroad spark ignition (SI) emission 

impacts of E10 were based on EPA’s 

NONROAD model and show trends 

similar to light duty vehicles. Biodiesel 

effects for this analysis were based on a 

new analysis of recent biodiesel testing, 

detailed in the DRIA, showing a 2% 

increase in NOX with a 20% biodiesel 

blend, a 16% decrease in PM, and a 

14% decrease in HC. These results 

essentially confirm the results of an 

earlier EPA analysis. 

Summarized vehicle and equipment 

emission impacts in 2022 are shown in 

Table VII.C–1 and VII.C–2 for the ‘‘less 

sensitive’’ and ‘‘more sensitive’’ cases. 

Table VII.C–3 shows the biodiesel 

contribution to these impacts, which are 

comparatively small. While the two fuel 

effect scenarios only differ with respect 

to exhaust emissions from cars and 

trucks, the totals shown below reflect 

the net impacts from all mobile sources, 

including car and truck evaporative 

emissions, off road emissions, and 

portable fuel containers, using the same 

emissions impacts for these sources in 

both cases. Additional breakdowns by 

mobile source category can be found in 

Chapter 3 of the DRIA. 

As shown in Tables VII.C–1 and 

VII.C–2, the vehicle and equipment 

ethanol impacts vary widely between 

the two fuel effects cases. Under the 

‘‘less sensitive’’ case, CO and benzene 

are projected to decrease in 2022 under 

today’s proposal, while NOX, HC and 

the other air toxics (except acrolein) are 

projected to increase due to the impacts 

of E10. For the ‘‘more sensitive’’ case, 

NOX impacts are higher and HC impacts 

lower due to the E10 effects on cars and 

trucks, and the inclusion of E85 effects 

leads to larger reductions in CO, 

benzene and 1,3-butadiene but more 

significant increases in ethanol, 

acetaldehyde and formaldehyde. The 

impacts on acrolein emissions in both 

cases, and on naphthalene in the ‘‘more 

sensitive’’ case depend on which 

reference case is considered, with small 

increases relative to the RFS1 base and 

mandate cases and a decrease relative to 

the AEO reference case. 

TABLE VII.C–1—2022 VEHICLE AND EQUIPMENT ‘‘LESS SENSITIVE’’ CASE EMISSION IMPACTS BY FUEL TYPE RELATIVE TO

EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

NOX .......................................................... 71,359 0.6 52,250 0.5 11,784 0.11 

HC ............................................................ 35,106 0.3 25,659 0.2 9,308 0.08 

PM10 ......................................................... ¥177 0.00 ¥177 0.00 ¥177 0.00 

PM2.5 ........................................................ ¥98 0.00 ¥98 0.00 ¥98 0.00 

CO ............................................................ ¥2,531,205 ¥4.7 ¥1,849,728 ¥3.4 ¥406,599 ¥0.8 

Benzene ................................................... ¥1,122 ¥0.7 ¥821 ¥0.5 ¥174 ¥0.1 

Ethanol ..................................................... 95,493 16.5 69,795 12.1 15,383 2.7 

1,3-Butadiene ........................................... 328 2.7 238 2.0 48 0.4 

Acetaldehyde ........................................... 5,057 13.6 3,689 9.9 793 2.1 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25063 

331The proposed standards may also impact 

levels of ambient CO, a criteria pollutant (see Table 

VII.A–1 above for co-pollutant emission impacts). 

For this analysis, however, we focus on the 

proposal’s impacts on ambient PM2.5 and ozone 

formation, since CO is a relatively minor problem 

in comparison to some of the other criteria 

pollutants. For example, as of August 15, 2008 there 

are approximately 675,000 people living in 3 areas 

(which include 4 counties) that are designated as 

nonattainment for CO. 

332 U.S. EPA (2003) National Air Quality and 

Trends Report, 2003 Special Studies Edition. Office 

of Air Quality Planning and Standards, Research 

Triangle Park, NC. Publication No. EPA 454/R–03– 

005. http://www.epa.gov/air/airtrends/aqtrnd03/ 

http://www.epa.gov/air/airtrends/aqtrnd03/. 

333 U.S. EPA (2007) Final Regulatory Impact 

Analysis: Control of Hazardous Air Pollutants from 

Mobile Sources, Office of Transportation and Air 

Quality, Ann Arbor, MI, Publication No. EPA420– 

R–07–002. http://www.epa.gov/otaq/toxics.htm 

334U.S. Environmental Protection Agency (2007). 

Control of Hazardous Air Pollutants from Mobile 

Sources; Final Rule. 72 FR 8434, February 26, 2007. 

TABLE VII.C–1—2022 VEHICLE AND EQUIPMENT ‘‘LESS SENSITIVE’’ CASE EMISSION IMPACTS BY FUEL TYPE RELATIVE TO

EACH REFERENCE CASE—Continued 

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Formaldehyde .......................................... 771 1.1 548 0.8 76 0.11 

Naphthalene ............................................. 10 0.07 8 0.05 3 0.02 

Acrolein .................................................... 12 0.2 8 0.14 ¥0.4 ¥0.01 

SO2 ........................................................... 0 0.0 0 0.0 0 0.0 

NH3 ........................................................... 0 0.0 0 0.0 0 0.0 

TABLE VII.C–2—2022 VEHICLE AND EQUIPMENT ‘‘MORE SENSITIVE’’ CASE EMISSION IMPACTS BY FUEL TYPE RELATIVE

TO EACH REFERENCE CASE

Pollutant 

RFS1 base RFS1 mandate AEO2007 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

Annual short 

tons 

Percent of 

total U.S. 

inventory 

NOX .......................................................... 161,754 1.4 118,295 1.1 26,266 0.2 

HC ............................................................ 23,018 0.2 16,828 0.15 1,553 0.01 

PM10 ......................................................... ¥4,289 ¥0.12 ¥4,289 ¥0.12 ¥4,289 ¥0.12 

PM2.5 ........................................................ ¥3,884 ¥0.12 ¥3,884 ¥0.12 ¥3,884 ¥0.12 

CO ............................................................ ¥3,966,131 ¥7.4 ¥3,284,654 ¥6.1 ¥1,841,524 ¥3.4 

Benzene ................................................... ¥4,293 ¥2.6 ¥3,808 ¥2.3 ¥2,770 ¥1.6 

Ethanol ..................................................... 113,376 19.6 87,792 15.2 36,886 6.4 

1,3-Butadiene ........................................... ¥228 ¥1.9 ¥298 ¥2.5 ¥446 ¥3.7 

Acetaldehyde ........................................... 8,915 24.0 7,598 20.4 4,809 12.9 

Formaldehyde .......................................... 2,497 3.5 2,324 3.2 1,958 2.7 

Naphthalene ............................................. ¥170 ¥1.2 ¥172 ¥1.2 ¥182 ¥1.3 

Acrolein .................................................... ¥25 ¥0.4 ¥27 ¥0.5 ¥31 ¥0.5 

SO2 ........................................................... 0 0.0 0 0.0 0 0.0 

NH3 ........................................................... 0 0.0 0 0.0 0 0.0 

TABLE VII.C–3—2022 VEHICLE AND

EQUIPMENT BIODIESEL EMISSION IMPACTS RELATIVE TO ALL REFERENCE

CASES

[these impacts are included in Tables VII.C–1 

and VII.C–2] 

Pollutant 

Biodiesel 

impacts 

Annual 

short tons 

NOX .......................................... 418 

HC ............................................. ¥753 

PM10 .......................................... ¥177 

PM2.5 ......................................... ¥98 

CO ............................................ ¥1,275 

Benzene .................................... ¥9.4 

Ethanol ...................................... 0.0 

1,3-Butadiene ........................... ¥5.1 

Acetaldehyde ............................ ¥21 

Formaldehyde ........................... ¥57 

Naphthalene ............................. ¥0.12 

Acrolein ..................................... ¥2.7 

SO2 ........................................... 0.0 

NH3 ........................................... 0.0 

D. Air Quality Impacts 

Although the purpose of this proposal 

is to implement the renewable fuel 

requirements established by the Energy 

Independence and Security Act (EISA) 

of 2007, this proposed rule would also 

impact emissions of criteria and air 

toxic pollutants. We first present current 

levels of PM2.5, ozone and air toxics and 

then discuss the national-scale air 

quality modeling analysis that will be 

performed for the final rule. 

1. Current Levels of PM2.5, Ozone and 

Air Toxics 

This proposal may have impacts on 

levels of PM2.5, ozone and air toxics.331

Nationally, levels of PM2.5, ozone and 

air toxics are declining.332 333 However, 

as of December 16, 2008, approximately 

88 million people live in the 39 areas 

that are designated as nonattainment for 

the 1997 PM2.5 National Ambient Air 

Quality Standard (NAAQS) and 

approximately 132 million people live 

in the 57 areas that are designated as 

nonattainment for the 1997 8-hour 

ozone NAAQS. The 1997 PM2.5 NAAQS 

was recently revised and the 2006 24- 

hour PM2.5 NAAQS became effective on 

December 18, 2006. Area designations 

for the 2006 24-hour PM2.5 NAAQS are 

expected to be promulgated in 2009 and 

become effective 90 days after 

publication in the Federal Register. In 

addition, the majority of Americans 

continue to be exposed to ambient 

concentrations of air toxics at levels 

which have the potential to cause 

adverse health effects.334 The levels of 

air toxics to which people are exposed 

vary depending on where people live 

and work and the kinds of activities in 

which they engage, as discussed in 

25064 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

335U.S. Environmental Protection Agency (2007). 

Control of Hazardous Air Pollutants from Mobile 

Sources; Final Rule. 72 FR 8434, February 26, 2007. 

336U.S. Environmental Protection Agency, Byun, 

D.W., and Ching, J.K.S., Eds, 1999. Science 

algorithms of EPA Models-3 Community Multiscale 

Air Quality (CMAQ modeling system, EPA/600/R– 

99/030, Office of Research and Development). 

337Byun, D.W., and Schere, K.L., 2006. Review of 

the Governing Equations, Computational 

Algorithms, and Other Components of the Models3 Community Multiscale Air Quality (CMAQ) 

Modeling System, J. Applied Mechanics Reviews, 

59 (2), 51–77. 

338 Dennis, R.L., Byun, D.W., Novak, J.H., 

Galluppi, K.J., Coats, C.J., and Vouk, M.A., 1996. 

The next generation of integrated air quality 

modeling: EPA’s Models-3, Atmospheric 

Environment, 30, 1925–1938. 

339U.S. EPA (2007). Regulatory Impact Analysis 

of the Proposed Revisions to the National Ambient 

Air Quality Standards for Ground-Level Ozone. 

EPA document number 442/R–07–008, July 2007. 

340Aiyyer, A., Cohan, D., Russell, A., Stockwell, 

W., Tanrikulu, S., Vizuete, W., Wilczak, J., 2007. 

Final Report: Third Peer Review of the CMAQ 

Model. p. 23. 

detail in U.S. EPA’s recent Mobile 

Source Air Toxics Rule.335

EPA has already adopted many 

emission control programs that are 

expected to reduce ambient PM2.5, 

ozone and air toxics levels. These 

control programs include the Small SI 

and Marine SI Engine Rule (73 FR 

59034, October 8, 2008), Locomotive 

and Commercial Marine Rule (73 FR 

25098, May 6, 2008), Mobile Source Air 

Toxics Rule (72 FR 8428, February 26, 

2007), Clean Air Interstate Rule (70 FR 

25162, May 12, 2005), Clean Air 

Nonroad Diesel Rule (69 FR 38957, June 

29, 2004), Heavy Duty Engine and 

Vehicle Standards and Highway Diesel 

Fuel Sulfur Control Requirements (66 

FR 5002, Jan. 18, 2001) and the Tier 2 

Motor Vehicle Emissions Standards and 

Gasoline Sulfur Control Requirements 

(65 FR 6698, Feb. 10, 2000). As a result 

of these programs, the ambient 

concentration of air toxics, PM2.5 and 

ozone in the future is expected to 

decrease. 

2. Impacts of Proposed Standards on 

Future Ambient Concentrations of 

PM2.5, Ozone and Air Toxics 

The atmospheric chemistry related to 

ambient concentrations of PM2.5, ozone 

and air toxics is very complex, making 

predictions based solely on emissions 

changes extremely difficult. For the 

final rule, a national-scale air quality 

modeling analysis will be performed to 

analyze the impacts of the proposed 

standards on ambient concentrations of 

PM2.5, ozone, and selected air toxics 

(i.e., benzene, formaldehyde, 

acetaldehyde, ethanol, acrolein and 1,3- 

butadiene). The length of time needed to 

prepare necessary inventory and model 

updates has precluded us from 

performing air quality modeling for this 

proposal. 

The air quality modeling we plan to 

perform (described more specifically 

below), will allow us to account for 

changes in the spatial distribution of PM 

and PM precursors, and changes in VOC 

speciation which could impact 

secondary PM formation. For example, 

reductions in aromatics in gasoline may 

reduce ambient PM concentrations by 

reducing secondary PM formation. 

Section 3.3 of the Draft Regulatory 

Impact Analysis (DRIA) for this 

proposal contains more information on 

aromatics and secondary aerosol 

formation. 

In addition, air quality modeling will 

account for changes in fuel type and 

spatial distribution of fuels that would 

change emissions of ozone precursor 

species and thus could affect ozone 

concentrations. Section 3.3 of the DRIA 

for this proposed rule provides more 

detail on the atmospheric chemistry and 

potential changes in ozone formation 

due to increased usage of ethanol fuels. 

Section VII.A above presents 

projections of the changes in air toxics 

emissions due to the proposed 

standards. The substantial increase in 

emissions of ethanol and acetaldehyde 

suggests a likely increase in ambient 

levels of acetaldehyde from both direct 

emissions and secondary formation as 

ethanol breaks down in the atmosphere. 

Formaldehyde and acrolein emissions 

would also increase somewhat, while 

emissions of benzene and 1,3-butadiene 

would decrease as a result of the 

proposed standards. Full-scale 

photochemical modeling is necessary to 

provide the needed spatial and temporal 

detail to more completely and 

accurately estimate the changes in 

ambient levels of these pollutants. 

For the final rule, EPA intends to use 

a 2005-based Community Multi-scale 

Air Quality (CMAQ) modeling platform 

as the tool for the air quality modeling. 

The CMAQ modeling system is a 

comprehensive three-dimensional gridbased Eulerian air quality model 

designed to estimate the formation and 

fate of oxidant precursors, primary and 

secondary PM concentrations and 

deposition, and air toxics, over regional 

and urban spatial scales (e.g., over the 

contiguous U.S.).336 337 338 The CMAQ 

model is a well-known and wellestablished tool and is commonly used 

by EPA for regulatory analyses, for 

instance the recent ozone NAAQS 

proposal, and by States in developing 

attainment demonstrations for their 

State Implementation Plans.339 The 

CMAQ model (version 4.6) was peerreviewed in February of 2007 for EPA as 

reported in ‘‘Third Peer Review of 

CMAQ Model,’’ and the peer review 

report for version 4.7 (described below) 

is currently being finalized.340

CMAQ includes many science 

modules that simulate the emission, 

production, decay, deposition and 

transport of organic and inorganic gasphase and particle-phase pollutants in 

the atmosphere. We intend to use the 

most recent CMAQ version (version 4.7) 

which was officially released by EPA’s 

Office of Research and Development 

(ORD) in December 2008, and reflects 

updates to earlier versions in a number 

of areas to improve the underlying 

science. These include (1) enhanced 

secondary organic aerosol (SOA) 

mechanism to include chemistry of 

isoprene, sesquiterpene, and aged incloud biogenic SOA in addition to 

terpene; (2) improved vertical 

convective mixing; (3) improved 

heterogeneous reaction involving nitrate 

formation; and (4) an updated gas-phase 

chemistry mechanism, Carbon Bond 05 

(CB05), with extensions to model 

explicit concentrations of air toxic 

species as well as chlorine and mercury. 

This mechanism, CB05-toxics, also 

computes concentrations of species that 

are involved in aqueous chemistry and 

that are precursors to aerosols. Section 

3.3.3 of the DRIA for this proposal 

discusses SOA formation and details 

about the improvements made to the 

SOA mechanism within this recent 

release of CMAQ. 

E. Health Effects of Criteria and Air 

Toxic Pollutants 

1. Particulate Matter 

a. Background 

Particulate matter (PM) represents a 

broad class of chemically and physically 

diverse substances. It can be principally 

characterized as discrete particles that 

exist in the condensed (liquid or solid) 

phase spanning several orders of 

magnitude in size. PM is further 

described by breaking it down into size 

fractions. PM10 refers to particles 

generally less than or equal to 10 

micrometers (μm) in aerodynamic 

diameter. PM2.5 refers to fine particles, 

generally less than or equal to 2.5 μm in 

aerodynamic diameter. Inhalable (or 

‘‘thoracic’’) coarse particles refer to 

those particles generally greater than 2.5 

μm but less than or equal to 10 μm in 

aerodynamic diameter. Ultrafine PM 

refers to particles less than 100 

nanometers (0.1 μm) in aerodynamic 

diameter. Larger particles tend to be 

removed by the respiratory clearance 

mechanisms (e.g., coughing), whereas 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25065 

341U.S. EPA (2004) Air Quality Criteria for 

Particulate Matter (Oct. 2004), Volume I Document 

No. EPA600/P–99/002aF and Volume II Document 

No. EPA600/P–99/002bF. This document is 

available in Docket EPA–HQ–OAR–2005–0161. 

342U.S. EPA (2005) Review of the National 

Ambient Air Quality Standard for Particulate 

Matter: Policy Assessment of Scientific and 

Technical Information, OAQPS Staff Paper. EPA– 

452/R–05–005. This document is available in 

Docket EPA–HQ–OAR–2005–0161. 

343 Dockery, D.W.; Pope, C.A. III: Xu, X.; et al. 

1993. An association between air pollution and 

mortality in six U.S. cities. N Engl J Med 329:1753– 

1759. 

344Pope, C.A., III; Burnett, R.T.; Thun, M.J.; Calle, 

E.E.; Krewski, D.; Ito, K.; Thurston, G.D. (2002) 

Lung cancer, cardiopulmonary mortality, and longterm exposure to fine particulate air pollution. J. 

Am. Med. Assoc. 287:1132–1141. 

345U.S. EPA Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). U.S. 

Environmental Protection Agency, Washington, 

D.C., EPA 600/R–05/004aF–cF, 2006. This 

document is available in Docket EPA–HQ–OAR– 

2005–0161. This document may be accessed 

electronically at: http://www.epa.gov/ttn/naaqs/ 

standards/ozone/s_o3_cr_cd.html. 

346U.S. EPA Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). U.S. 

Environmental Protection Agency, Washington, DC, 

EPA 600/R–05/004aF–cF, 2006. This document is 

available in Docket EPA–HQ–OAR–2005–0161. 

This document may be accessed electronically at: 

http://www.epa.gov/ttn/naaqs/standards/ozone/ 

s_o3_cr_cd.html. 

347U.S. EPA (2007) Review of the National 

Ambient Air Quality Standards for Ozone, Policy 

Assessment of Scientific and Technical 

Information. OAQPS Staff Paper.EPA–452/R–07– 

003. This document is available in Docket EPA– 

HQ–OAR–2005–0161. This document is available 

electronically at: http:www.epa.gov/ttn/naaqs/ 

standards/ozone/s_o3_cr_sp.html.. 

348National Research Council (NRC), 2008. 

Estimating Mortality Risk Reduction and Economic 

Benefits from Controlling Ozone Air Pollution. The 

National Academies Press: Washington, DC. 

smaller particles are deposited deeper in 

the lungs. 

Fine particles are produced primarily 

by combustion processes and by 

transformations of gaseous emissions 

(e.g., SOX, NOX and VOC) in the 

atmosphere. The chemical and physical 

properties of PM2.5 may vary greatly 

with time, region, meteorology and 

source category. Thus, PM2.5 may 

include a complex mixture of different 

pollutants including sulfates, nitrates, 

organic compounds, elemental carbon 

and metal compounds. These particles 

can remain in the atmosphere for days 

to weeks and travel hundreds to 

thousands of kilometers. 

b. Health Effects of PM 

Scientific studies show ambient PM is 

associated with a series of adverse 

health effects. These health effects are 

discussed in detail in the 2004 EPA 

Particulate Matter Air Quality Criteria 

Document (PM AQCD), and the 2005 

PM Staff Paper.341 342 Further discussion 

of health effects associated with PM can 

also be found in the DRIA for this rule. 

Health effects associated with shortterm exposures (hours to days) to 

ambient PM include premature 

mortality, increased hospital 

admissions, heart and lung diseases, 

increased cough, adverse lowerrespiratory symptoms, decrements in 

lung function and changes in heart rate 

rhythm and other cardiac effects. 

Studies examining populations exposed 

to different levels of air pollution over 

a number of years, including the 

Harvard Six Cities Study and the 

American Cancer Society Study, show 

associations between long-term 

exposure to ambient PM2.5 and both 

total and cardiovascular and respiratory 

mortality.343 In addition, a reanalysis of 

the American Cancer Society Study 

shows an association between fine 

particle and sulfate concentrations and 

lung cancer mortality.344

2. Ozone 

a. Background 

Ground-level ozone pollution is 

typically formed by the reaction of 

volatile organic compounds (VOC) and 

nitrogen oxides (NOX) in the lower 

atmosphere in the presence of heat and 

sunlight. These pollutants, often 

referred to as ozone precursors, are 

emitted by many types of pollution 

sources, such as highway and nonroad 

motor vehicles and engines, power 

plants, chemical plants, refineries, 

makers of consumer and commercial 

products, industrial facilities, and 

smaller area sources. 

The science of ozone formation, 

transport, and accumulation is 

complex.345 Ground-level ozone is 

produced and destroyed in a cyclical set 

of chemical reactions, many of which 

are sensitive to temperature and 

sunlight. When ambient temperatures 

and sunlight levels remain high for 

several days and the air is relatively 

stagnant, ozone and its precursors can 

build up and result in more ozone than 

typically occurs on a single hightemperature day. Ozone can be 

transported hundreds of miles 

downwind from precursor emissions, 

resulting in elevated ozone levels even 

in areas with low local VOC or NOX

emissions. 

b. Health Effects of Ozone 

The health and welfare effects of 

ozone are well documented and are 

assessed in EPA’s 2006 Ozone Air 

Quality Criteria Document (ozone 

AQCD) and 2007 Staff Paper.346 347

Ozone can irritate the respiratory 

system, causing coughing, throat 

irritation, and/or uncomfortable 

sensation in the chest. Ozone can 

reduce lung function and make it more 

difficult to breathe deeply; breathing 

may also become more rapid and 

shallow than normal, thereby limiting a 

person’s activity. Ozone can also 

aggravate asthma, leading to more 

asthma attacks that require medical 

attention and/or the use of additional 

medication. In addition, there is 

suggestive evidence of a contribution of 

ozone to cardiovascular-related 

morbidity and highly suggestive 

evidence that short-term ozone exposure 

directly or indirectly contributes to nonaccidental and cardiopulmonary-related 

mortality, but additional research is 

needed to clarify the underlying 

mechanisms causing these effects. In a 

recent report on the estimation of ozonerelated premature mortality published 

by the National Research Council (NRC), 

a panel of experts and reviewers 

concluded that short-term exposure to 

ambient ozone is likely to contribute to 

premature deaths and that ozone-related 

mortality should be included in 

estimates of the health benefits of 

reducing ozone exposure.348 Animal 

toxicological evidence indicates that 

with repeated exposure, ozone can 

inflame and damage the lining of the 

lungs, which may lead to permanent 

changes in lung tissue and irreversible 

reductions in lung function. People who 

are more susceptible to effects 

associated with exposure to ozone can 

include children, the elderly, and 

individuals with respiratory disease 

such as asthma. Those with greater 

exposures to ozone, for instance due to 

time spent outdoors (e.g., children and 

outdoor workers), are also of particular 

concern. 

The 2006 ozone AQCD also examined 

relevant new scientific information that 

has emerged in the past decade, 

including the impact of ozone exposure 

on such health effects as changes in 

lung structure and biochemistry, 

inflammation of the lungs, exacerbation 

and causation of asthma, respiratory 

illness-related school absence, hospital 

admissions and premature mortality. 

Animal toxicological studies have 

suggested potential interactions between 

ozone and PM, with increased responses 

observed to mixtures of the two 

pollutants compared to either ozone or 

PM alone. The respiratory morbidity 

observed in animal studies along with 

the evidence from epidemiologic studies 

supports a causal relationship between 

acute ambient ozone exposures and 

increased respiratory-related emergency 

room visits and hospitalizations in the 

warm season. In addition, there is 

25066 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

349U.S. EPA (2000). Air Quality Criteria for 

Carbon Monoxide, EPA/600/P–99/001F. This 

document is available in Docket EPA–HQ–OAR– 

2005–0161. 

350U.S. EPA (2000). Air Quality Criteria for 

Carbon Monoxide, EPA/600/P–99/001F. This 

document is available in Docket EPA–HQ–OAR– 

2005–0161. 

351U. S. EPA. 1999 National-Scale Air Toxics 

Assessment. http://www.epa.gov/ttn/atw/nata1999/ 

risksum.html 

352U.S. EPA. 2006. National-Scale Air Toxics 

Assessment for 1999. http://www.epa.gov/ttn/atw/ 

nata1999 

353U.S. EPA. 1991. Integrated Risk Information 

System File of Acetaldehyde. Research and 

Development, National Center for Environmental 

Assessment, Washington, DC. This material is 

available electronically at. 

354U.S. Department of Health and Human 

Services National Toxicology Program 11th Report 

on Carcinogens available at: ntp.niehs.nih.gov/ 

index.cfm?objectid=32BA9724-F1F6-975E7FCE50709CB4C932. 

355 International Agency for Research on Cancer 

(IARC). 1999. Re-evaluation of some organic 

chemicals, hydrazine, and hydrogen peroxide. IARC 

Monographs on the Evaluation of Carcinogenic Risk 

of Chemical to Humans, Vol 71. Lyon, France. 

356U.S. EPA. 1991. Integrated Risk Information 

System File of Acetaldehyde. This material is 

available electronically at http://www.epa.gov/iris/ 

subst/0290.htm. 

357Appleman, L. M., R. A. Woutersen, V. J. Feron, 

R. N. Hooftman, and W. R. F. Notten. 1986. Effects 

of the variable versus fixed exposure levels on the 

toxicity of acetaldehyde in rats. J. Appl. Toxicol. 6: 

331–336. 

358Appleman, L.M., R.A. Woutersen, and V.J. 

Feron. 1982. Inhalation toxicity of acetaldehyde in 

rats. I. Acute and subacute studies. Toxicology. 23: 

293–297. 

359Myou, S.; Fujimura, M.; Nishi, K.; Ohka, T.; 

and Matsuda, T. 1993. Aerosolized acetaldehyde 

induces histamine-mediated bronchoconstriction in 

asthmatics. Am. Rev. Respir. Dis. 148 (4 Pt 1): 940– 

3. 

360U.S. EPA. 2003. Integrated Risk Information 

System File of Acrolein. Research and 

Development, National Center for Environmental 

Assessment, Washington, DC. This material is 

available at http://www.epa.gov/iris/subst/ 

0364.htm. 

361 International Agency for Research on Cancer 

(IARC). 1995. Monographs on the evaluation of 

carcinogenic risk of chemicals to humans, Volume 

63, Dry cleaning, some chlorinated solvents and 

other industrial chemicals, World Health 

Organization, Lyon, France. 

362Weber-Tschopp, A.; Fischer, T.; Gierer, R.; et 

al. (1977) Experimentelle reizwirkungen von 

Acrolein auf den Menschen. Int Arch Occup 

Environ Hlth 40(2):117–130. In German. 

363Sim, V.M.; Pattle, R.E. (1957) Effect of possible 

smog irritants on human subjects. J Am Med Assoc 

165(15):1908–1913. 

364Morris J.B., Symanowicz P.T., Olsen J.E., et al. 

2003. Immediate sensory nerve-mediated 

respiratory responses to irritants in healthy and 

allergic airway-diseased mice. J Appl Physiol 

94(4):1563–1571. 

365Sim V.M., Pattle R.E. Effect of possible smog 

irritants on human subjects. JAMA 165:1980–2010, 

1957. 

suggestive evidence of a contribution of 

ozone to cardiovascular-related 

morbidity and non-accidental and 

cardiopulmonary mortality. 

3. Carbon Monoxide 

Carbon monoxide (CO) forms as a 

result of incomplete fuel combustion. 

CO enters the bloodstream through the 

lungs, forming carboxyhemoglobin and 

reducing the delivery of oxygen to the 

body’s organs and tissues. The health 

threat from CO is most serious for those 

who suffer from cardiovascular disease, 

particularly those with angina or 

peripheral vascular disease. Healthy 

individuals also are affected, but only at 

higher CO levels. Exposure to elevated 

CO levels is associated with impairment 

of visual perception, work capacity, 

manual dexterity, learning ability and 

performance of complex tasks. Carbon 

monoxide also contributes to ozone 

nonattainment since carbon monoxide 

reacts photochemically in the 

atmosphere to form ozone.349

Additional information on CO related 

health effects can be found in the 

Carbon Monoxide Air Quality Criteria 

Document (CO AQCD).350

4. Air Toxics 

The population experiences an 

elevated risk of cancer and noncancer 

health effects from exposure to the class 

of pollutants known collectively as ‘‘air 

toxics.’’351 Fuel combustion contributes 

to ambient levels of air toxics that can 

include, but are not limited to, 

acetaldehyde, acrolein, benzene, 1,3- 

butadiene, formaldehyde, ethanol, 

naphthalene and peroxyacetyl nitrate 

(PAN). Acrolein, benzene, 1,3- 

butadiene, formaldehyde and 

naphthalene have significant 

contributions from mobile sources and 

were identified as national or regional 

risk drivers in the 1999 National-scale 

Air Toxics Assessment (NATA).352

PAN, which is formed from precursor 

compounds by atmospheric processes, 

is not assessed in NATA. Emissions and 

ambient concentrations of compounds 

are discussed in the DRIA chapter on 

emission inventories and air quality 

(Chapter 3). 

a. Acetaldehyde 

Acetaldehyde is classified in EPA’s 

IRIS database as a probable human 

carcinogen, based on nasal tumors in 

rats, and is considered toxic by the 

inhalation, oral, and intravenous 

routes.353 Acetaldehyde is reasonably 

anticipated to be a human carcinogen by 

the U.S. DHHS in the 11th Report on 

Carcinogens and is classified as possibly 

carcinogenic to humans (Group 2B) by 

the IARC.354 355 EPA is currently 

conducting a reassessment of cancer risk 

from inhalation exposure to 

acetaldehyde. 

The primary noncancer effects of 

exposure to acetaldehyde vapors 

include irritation of the eyes, skin, and 

respiratory tract.356 In short-term (4 

week) rat studies, degeneration of 

olfactory epithelium was observed at 

various concentration levels of 

acetaldehyde exposure.357 358 Data from 

these studies were used by EPA to 

develop an inhalation reference 

concentration. Some asthmatics have 

been shown to be a sensitive 

subpopulation to decrements in 

functional expiratory volume (FEV1 

test) and bronchoconstriction upon 

acetaldehyde inhalation.359 The agency 

is currently conducting a reassessment 

of the health hazards from inhalation 

exposure to acetaldehyde. 

b. Acrolein 

EPA determined in 2003 that the 

human carcinogenic potential of 

acrolein could not be determined 

because the available data were 

inadequate. No information was 

available on the carcinogenic effects of 

acrolein in humans and the animal data 

provided inadequate evidence of 

carcinogenicity.360 The IARC 

determined in 1995 that acrolein was 

not classifiable as to its carcinogenicity 

in humans.361

Acrolein is extremely acrid and 

irritating to humans when inhaled, with 

acute exposure resulting in upper 

respiratory tract irritation, mucus 

hypersecretion and congestion. Levels 

considerably lower than 1 ppm (2.3 mg/ 

m3) elicit subjective complaints of eye 

and nasal irritation and a decrease in 

the respiratory rate.362 363 Lesions to the 

lungs and upper respiratory tract of rats, 

rabbits, and hamsters have been 

observed after subchronic exposure to 

acrolein. Based on animal data, 

individuals with compromised 

respiratory function (e.g., emphysema, 

asthma) are expected to be at increased 

risk of developing adverse responses to 

strong respiratory irritants such as 

acrolein. This was demonstrated in mice 

with allergic airway disease by 

comparison to non-diseased mice in a 

study of the acute respiratory irritant 

effects of acrolein.364

The intense irritancy of this carbonyl 

has been demonstrated during 

controlled tests in human subjects, who 

suffer intolerable eye and nasal mucosal 

sensory reactions within minutes of 

exposure.365

c. Benzene 

The EPA’s IRIS database lists benzene 

as a known human carcinogen (causing 

leukemia) by all routes of exposure, and 

concludes that exposure is associated 

with additional health effects, including 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25067 

366U.S. EPA. 2000. Integrated Risk Information 

System File for Benzene. This material is available 

electronically at http://www.epa.gov/iris/subst/ 

0276.htm. 

367 International Agency for Research on Cancer 

(IARC). 1982. Monographs on the evaluation of 

carcinogenic risk of chemicals to humans, Volume 

29, Some industrial chemicals and dyestuffs, World 

Health Organization, Lyon, France, p. 345–389. 

368 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; 

Henry, V.A. 1992. Synergistic action of the benzene 

metabolite hydroquinone on myelopoietic 

stimulating activity of granulocyte/macrophage 

colony-stimulating factor in vitro, Proc. Natl. Acad. 

Sci. 89:3691–3695. 

369 International Agency for Research on Cancer 

(IARC). 1987. Monographs on the evaluation of 

carcinogenic risk of chemicals to humans, Volume 

29, Supplement 7, Some industrial chemicals and 

dyestuffs, World Health Organization, Lyon, France. 

370U.S. Department of Health and Human 

Services National Toxicology Program, 11th Report 

on Carcinogens, available at: http:// 

ntp.niehs.nih.gov/go/16183. 

371Aksoy, M. (1989). Hematotoxicity and 

carcinogenicity of benzene. Environ. Health 

Perspect. 82:193–197. 

372 Goldstein, B.D. (1988). Benzene toxicity. 

Occupational medicine. State of the Art Reviews. 

3:541–554. 

373Rothman, N., G.L. Li, M. Dosemeci, W.E. 

Bechtold, G.E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, 

W. Lu, M.T. Smith, N. Titenko-Holland, L.P. Zhang, 

W. Blot, S.N. Yin, and R.B. Hayes (1996) 

Hematotoxicity among Chinese workers heavily 

exposed to benzene. Am. J. Ind. Med. 29:236–246. 

374U.S. EPA (2002) Toxicological Review of 

Benzene (Noncancer Effects). Environmental 

Protection Agency, Integrated Risk Information 

System (IRIS), Research and Development, National 

Center for Environmental Assessment, Washington 

DC. This material is available electronically at 

http://www.epa.gov/iris/subst/0276.htm. 

375Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; 

Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, 

S.; Li, H.; Rupa, D.; Suramaya, R.; Songnian, W.; 

Huifant, Y.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; 

Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003) HEI Report 

115, Validation & Evaluation of Biomarkers in 

Workers Exposed to Benzene in China. 

376Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. 

Cohen, et al. (2002) Hematological changes among 

Chinese workers with a broad range of benzene 

exposures. Am. J. Industr. Med. 42:275–285. 

377Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et 

al. (2004) Hematotoxicity in Workers Exposed to 

Low Levels of Benzene. Science 306:1774–1776. 

378Turtletaub, K.W. and Mani, C. (2003) Benzene 

metabolism in rodents at doses relevant to human 

exposure from Urban Air. Research Reports Health 

Effect Inst. Report No. 113. 

379U.S. EPA (2002) Health Assessment of 1,3– 

Butadiene. Office of Research and Development, 

National Center for Environmental Assessment, 

Washington Office, Washington, DC. Report No. 

EPA600–P–98–001F. This document is available 

electronically at http://www.epa.gov/iris/supdocs/ 

buta-sup.pdf. 

380U.S. EPA (2002) Full IRIS Summary for 1,3- 

butadiene (CASRN 106–99–0). Environmental 

Protection Agency, Integrated Risk Information 

System (IRIS), Research and Development, National 

Center for Environmental Assessment, Washington, 

DC, http://www.epa.gov/iris/subst/0139.htm. 

381 International Agency for Research on Cancer 

(IARC) (1999) Monographs on the evaluation of 

carcinogenic risk of chemicals to humans, Volume 

71, Re-evaluation of some organic chemicals, 

hydrazine and hydrogen peroxide and Volume 97 

(in preparation), World Health Organization, Lyon, 

France. 

382U.S. Department of Health and Human 

Services (2005) National Toxicology Program, 11th 

Report on Carcinogens, available at: http:// 

ntp.niehs.nih.gov/index.cfm?objectid=32BA9724– 

F1F6–975E–7FCE50709CB4C932. 

383Bevan, C.; Stadler, J.C.; Elliot, G.S.; et al. 

(1996) Subchronic toxicity of 4-vinylcyclohexene in 

rats and mice by inhalation. Fundam. Appl. 

Toxicol. 32:1–10. 

384 International Agency for Research on Cancer 

(IARC). 1988. Monographs on the evaluation of 

carcinogenic risk of chemicals to humans, Volume 

44, Alcohol Drinking, World Health Organization, 

Lyon, France. 

385U.S. Department of Health and Human 

Services. 2005. National Toxicology Program 11th 

Report on Carcinogens available at: 

ntp.niehs.nih.gov/index.cfm?objectid=32BA9724- 

F1F6-975E-7FCE50709CB4C932. 

genetic changes in both humans and 

animals and increased proliferation of 

bone marrow cells in mice.366 367 368 EPA 

states in its IRIS database that data 

indicate a causal relationship between 

benzene exposure and acute 

lymphocytic leukemia and suggest a 

relationship between benzene exposure 

and chronic non-lymphocytic leukemia 

and chronic lymphocytic leukemia. The 

International Agency for Research on 

Carcinogens (IARC) has determined that 

benzene is a human carcinogen and the 

U.S. Department of Health and Human 

Services (DHHS) has characterized 

benzene as a known human 

carcinogen.369 370

A number of adverse noncancer 

health effects including blood disorders, 

such as preleukemia and aplastic 

anemia, have also been associated with 

long-term exposure to benzene.371 372

The most sensitive noncancer effect 

observed in humans, based on current 

data, is the depression of the absolute 

lymphocyte count in blood.373 374 In 

addition, recent work, including studies 

sponsored by the Health Effects Institute 

(HEI), provides evidence that 

biochemical responses are occurring at 

lower levels of benzene exposure than 

previously known.375 376 377 378 EPA’s 

IRIS program has not yet evaluated 

these new data. 

d. 1,3-Butadiene 

EPA has characterized 1,3-butadiene 

as carcinogenic to humans by 

inhalation.379 380 The IARC has 

determined that 1,3-butadiene is a 

human carcinogen and the U.S. DHHS 

has characterized 1,3-butadiene as a 

known human carcinogen.381 382 There 

are numerous studies consistently 

demonstrating that 1,3-butadiene is 

metabolized into genotoxic metabolites 

by experimental animals and humans. 

The specific mechanisms of 1,3- 

butadiene-induced carcinogenesis are 

unknown; however, the scientific 

evidence strongly suggests that the 

carcinogenic effects are mediated by 

genotoxic metabolites. Animal data 

suggest that females may be more 

sensitive than males for cancer effects 

associated with 1,3-butadiene exposure; 

there are insufficient data in humans 

from which to draw conclusions about 

sensitive subpopulations. 1,3-butadiene 

also causes a variety of reproductive and 

developmental effects in mice; no 

human data on these effects are 

available. The most sensitive effect was 

ovarian atrophy observed in a lifetime 

bioassay of female mice.383

e. Ethanol 

EPA is conducting an assessment of 

the cancer and noncancer effects of 

exposure to ethanol, a compound which 

is not currently listed in EPA’s IRIS. A 

description of these effects to the extent 

that information is available will be 

presented, as required by Section 1505 

of EPAct, in a report to Congress on 

public health, air quality and water 

resource impacts of fuel additives. We 

expect to release that report in 2009. 

Extensive data are available regarding 

adverse health effects associated with 

the ingestion of ethanol while data on 

inhalation exposure effects are sparse. 

As part of the IRIS assessment, 

pharmacokinetic models are being 

evaluated as a means of extrapolating 

across species (animal to human) and 

across exposure routes (oral to 

inhalation) to better characterize the 

health hazards and dose-response 

relationships for low levels of ethanol 

exposure in the environment. 

The IARC has classified ‘‘alcoholic 

beverages’’ as carcinogenic to humans 

based on sufficient evidence that 

malignant tumors of the mouth, 

pharynx, larynx, esophagus, and liver 

are causally related to the consumption 

of alcoholic beverages.384 The U.S. 

DHHS in the 11th Report on 

Carcinogens also identified ‘‘alcoholic 

beverages’’ as a known human 

carcinogen (they have not evaluated the 

cancer risks specifically from exposure 

to ethanol), with evidence for cancer of 

the mouth, pharynx, larynx, esophagus, 

liver and breast.385 There are no studies 

reporting carcinogenic effects from 

inhalation of ethanol. EPA is currently 

evaluating the available human and 

animal cancer data to identify which 

cancer type(s) are the most relevant to 

an assessment of risk to humans from a 

low-level oral and inhalation exposure 

to ethanol. 

Noncancer health effects data are 

available from animal studies as well as 

epidemiologic studies. The 

epidemiologic data are obtained from 

studies of alcoholic beverage 

25068 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

386U.S. Department of Health and Human 

Services. 2000. 10th Special Report to the U.S. 

Congress on Alcohol and Health. June 2000. 

387 Goodlett CR, KH Horn, F Zhou. 2005. Alcohol 

teratogenesis: mechanisms of damage and strategies 

for intervention. Exp. Biol. Med. 230:394–406. 

388Riley EP, CL McGee. 2005. Fetal alcohol 

spectrum disorders: an overview with emphasis on 

changes in brain and behavior. Exp. Biol. Med. 

230:357–365. 

389Zhang X, JH Sliwowska, J Weinberg. 2005. 

Prenatal alcohol exposure and fetal programming: 

effects on neuroendocrine and immune function. 

Exp. Biol. Med. 230:376–388. 

390Riley EP, CL McGee, ER Sowell. 2004. 

Teratogenic effects of alcohol: a decade of brain 

imaging. Am. J. Med. Genet. Part C: Semin. Med. 

Genet. 127:35–41. 

391 Gunzerath L, V Faden, S Zakhari, K Warren. 

2004. National Institute on Alcohol Abuse and 

Alcoholism report on moderate drinking. Alcohol. 

Clin. Exp. Res. 28:829–847. 

392World Health Organization (WHO). 2004. 

Global status report on alcohol 2004. Geneva, 

Switzerland: Department of Mental Health and 

Substance Abuse. Available: http://www.who.int/ 

substance_abuse/publications/ 

global_status_report_2004_overview.pdf. 

393Chen W–JA, SE Maier, SE Parnell, FR West. 

2003. Alcohol and the developing brain: 

neuroanatomical studies. Alcohol Res. Health 

27:174–180. 

394 Driscoll CD, AP Streissguth, EP Riley. 1990. 

Prenatal alcohol exposure comparability of effects 

in humans and animal models. Neurotoxicol. 

Teratol. 12:231–238. 

395U.S. EPA (1987) Assessment of Health Risks 

to Garment Workers and Certain Home Residents 

from Exposure to Formaldehyde, Office of 

Pesticides and Toxic Substances, April 1987. 

396Hauptmann, M.; Lubin, J. H.; Stewart, P. A.; 

Hayes, R. B.; Blair, A. 2003. Mortality from 

lymphohematopoietic malignancies among workers 

in formaldehyde industries. Journal of the National 

Cancer Institute 95: 1615–1623. 

397Hauptmann, M.; Lubin, J. H.; Stewart, P. A.; 

Hayes, R. B.; Blair, A. 2004. Mortality from solid 

cancers among workers in formaldehyde industries. 

American Journal of Epidemiology 159: 1117–1130. 

398Pinkerton, L. E. 2004. Mortality among a 

cohort of garment workers exposed to 

formaldehyde: an update. Occup. Environ. Med. 61: 

193–200. 

399Coggon, D, EC Harris, J Poole, KT Palmer. 

2003. Extended follow-up of a cohort of British 

chemical workers exposed to formaldehyde. J 

National Cancer Inst. 95:1608–1615. 

400 International Agency for Research on Cancer 

(IARC). 2006. Formaldehyde, 2-Butoxyethanol and 

1-tert-Butoxypropan-2-ol. Volume 88. (in 

preparation), World Health Organization, Lyon, 

France. 

401Agency for Toxic Substances and Disease 

Registry (ATSDR). 1999. Toxicological profile for 

Formaldehyde. Atlanta, GA: U.S. Department of 

Health and Human Services, Public Health Service. 

http://www.atsdr.cdc.gov/toxprofiles/tp111.html. 

402WHO (2002) Concise International Chemical 

Assessment Document 40: Formaldehyde. 

Published under the joint sponsorship of the United 

Nations Environment Programme, the International 

Labour Organization, and the World Health 

Organization, and produced within the framework 

of the Inter-Organization Programme for the Sound 

Management of Chemicals. Geneva. 

403U.S. EPA. 2004. Toxicological Review of 

Naphthalene (Reassessment of the Inhalation 

Cancer Risk), Environmental Protection Agency, 

Integrated Risk Information System, Research and 

Development, National Center for Environmental 

Assessment, Washington, DC. This material is 

available electronically at http://www.epa.gov/iris/ 

subst/0436.htm. 

404Oak Ridge Institute for Science and Education. 

(2004). External Peer Review for the IRIS 

Reassessment of the Inhalation Carcinogenicity of 

Naphthalene. August 2004. http://cfpub.epa.gov/ 

ncea/cfm/recordisplay.cfm?deid=84403. 

405National Toxicology Program (NTP). (2004). 

11th Report on Carcinogens. Public Health Service, 

U.S. Department of Health and Human Services, 

Research Triangle Park, NC. Available from: 

http://ntp-server.niehs.nih.gov. 

406 International Agency for Research on Cancer 

(IARC). (2002). Monographs on the Evaluation of 

the Carcinogenic Risk of Chemicals for Humans. 

Vol. 82, Lyon, France. 

407U.S. EPA. 1998. Toxicological Review of 

Naphthalene, Environmental Protection Agency, 

Integrated Risk Information System, Research and 

Development, National Center for Environmental 

Assessment, Washington, DC. This material is 

available electronically at http://www.epa.gov/iris/ 

subst/0436.htm. 

consumption. Effects include 

neurological impairment, 

developmental effects, cardiovascular 

effects, immune system depression, and 

effects on the liver, pancreas and 

reproductive system.386 There is 

evidence that children prenatally 

exposed via mothers’ ingestion of 

alcoholic beverages during pregnancy 

are at increased risk of hyperactivity 

and attention deficits, impaired motor 

coordination, a lack of regulation of 

social behavior or poor psychosocial 

functioning, and deficits in cognition, 

mathematical ability, verbal fluency, 

and spatial 

memory.387 388 389 390 391 392 393 394 In some 

people, genetic factors influencing the 

metabolism of ethanol can lead to 

differences in internal levels of ethanol 

and may render some subpopulations 

more susceptible to risks from the 

effects of ethanol. 

f. Formaldehyde 

Since 1987, EPA has classified 

formaldehyde as a probable human 

carcinogen based on evidence in 

humans and in rats, mice, hamsters, and 

monkeys.395 EPA is currently reviewing 

recently published epidemiological 

data. For instance, research conducted 

by the National Cancer Institute (NCI) 

found an increased risk of 

nasopharyngeal cancer and 

lymphohematopoietic malignancies 

such as leukemia among workers 

exposed to formaldehyde.396 397 NCI is 

currently performing an update of these 

studies. A recent National Institute of 

Occupational Safety and Health 

(NIOSH) study of garment workers also 

found increased risk of death due to 

leukemia among workers exposed to 

formaldehyde.398 Extended follow-up of 

a cohort of British chemical workers did 

not find evidence of an increase in 

nasopharyngeal or 

lymphohematopoietic cancers, but a 

continuing statistically significant 

excess in lung cancers was reported.399

Recently, the IARC re-classified 

formaldehyde as a human carcinogen 

(Group 1).400

Formaldehyde exposure also causes a 

range of noncancer health effects, 

including irritation of the eyes (burning 

and watering of the eyes), nose and 

throat. Effects from repeated exposure in 

humans include respiratory tract 

irritation, chronic bronchitis and nasal 

epithelial lesions such as metaplasia 

and loss of cilia. Animal studies suggest 

that formaldehyde may also cause 

airway inflammation—including 

eosinophil infiltration into the airways. 

There are several studies that suggest 

that formaldehyde may increase the risk 

of asthma—particularly in the 

young.401 402

g. Naphthalene 

Naphthalene is found in small 

quantities in gasoline and diesel fuels. 

Naphthalene emissions have been 

measured in larger quantities in both 

gasoline and diesel exhaust compared 

with evaporative emissions from mobile 

sources, indicating it is primarily a 

product of combustion. EPA released an 

external review draft of a reassessment 

of the inhalation carcinogenicity of 

naphthalene based on a number of 

recent animal carcinogenicity 

studies.403 The draft reassessment 

completed external peer review.404

Based on external peer review 

comments received, additional analyses 

are being undertaken. This external 

review draft does not represent official 

agency opinion and was released solely 

for the purposes of external peer review 

and public comment. Once EPA 

evaluates public and peer reviewer 

comments, the document will be 

revised. The National Toxicology 

Program listed naphthalene as 

‘‘reasonably anticipated to be a human 

carcinogen’’ in 2004 on the basis of 

bioassays reporting clear evidence of 

carcinogenicity in rats and some 

evidence of carcinogenicity in mice.405

California EPA has released a new risk 

assessment for naphthalene, and the 

IARC has reevaluated naphthalene and 

re-classified it as Group 2B: possibly 

carcinogenic to humans.406 Naphthalene 

also causes a number of chronic noncancer effects in animals, including 

abnormal cell changes and growth in 

respiratory and nasal tissues.407

h. Peroxyacetyl Nitrate (PAN) 

Peroxyacetyl nitrate (PAN) has not 

been evaluated by EPA’s IRIS program. 

Information regarding the potential 

carcinogenicity of PAN is limited. As 

noted in the EPA air quality criteria 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25069 

408U.S. EPA. 2006. Air Quality Criteria for Ozone 

and Related Photochemical Oxidants (Ozone CD). 

Research Triangle Park, NC: National Center for 

Environmental Assessment; report no. EPA/600/R– 

05/004aF–cF.3v. page 5–78. Available at http:// 

cfpub.epa.gov/ncea/. 

409U.S. EPA. 2006. Air Quality Criteria for Ozone 

and Related Photochemical Oxidants (Final). U.S. 

Environmental Protection Agency, Washington, DC, 

EPA 600/R–05/004aF–cF. pages 5–63. This 

document is available in Docket EPA–HQ–OAR– 

2005–0161. This document may be accessed 

electronically at: http://www.epa.gov/ttn/naaqs/

standards/ozone/s_o3_cr_cd.html. 

410U.S. EPA. 2006. Air Quality Criteria for Ozone 

and Related Photochemical Oxidants (Final). U.S. 

Environmental Protection Agency, Washington, DC, 

EPA 600/R–05/004aF–cF. pages 5–78. This 

document is available in Docket EPA–HQ–OAR– 

2005–0161. This document may be accessed 

electronically at: http://www.epa.gov/ttn/naaqs/

standards/ozone/s_o3_cr_cd.html. 

411U.S. EPA. Integrated Risk Information System 

(IRIS) database is available at: www.epa.gov/iris. 

412National Research Council, 1993. Protecting 

Visibility in National Parks and Wilderness Areas. 

National Academy of Sciences Committee on Haze 

in National Parks and Wilderness Areas. National 

Academy Press, Washington, DC. This document is 

available in Docket EPA–HQ–OAR–2005–0161. 

This book can be viewed on the National Academy 

Press Web site at http://www.nap.edu/books/ 

0309048443/html/. 413U.S. EPA (2004) Air Quality Criteria for 

Particulate Matter (Oct 2004), Volume I Document 

No. EPA600/P–99/002aF and Volume II Document 

No. EPA600/P–99/002bF. This document is 

available in Docket EPA–HQ–OAR–2005–0161. 414U.S. EPA (2005) Review of the National 

Ambient Air Quality Standard for Particulate 

Matter: Policy Assessment of Scientific and 

Technical Information, OAQPS Staff Paper. EPA– 

452/R–05–005. This document is available in 

Docket EPA–HQ–OAR–2005–0161. 415These areas are defined in CAA section 162 as 

those national parks exceeding 6,000 acres, 

wilderness areas and memorial parks exceeding 

5,000 acres, and all international parks which were 

in existence on August 7, 1977. 

416U.S. EPA (2000) Deposition of Air Pollutants 

to the Great Waters: Third Report to Congress. 

Office of Air Quality Planning and Standards. EPA– 

453/R–00–0005. This document is available in 

Docket EPA–HQ–OAR–2005–0161. 

document for ozone and related 

photochemical oxidants, cytogenetic 

studies indicate that PAN is not a potent 

mutagen, clastogen (a compound that 

can cause breaks in chromosomes), or 

DNA-damaging agent in mammalian 

cells either in vivo or in vitro. Some 

studies suggest that PAN may be a weak 

bacterial mutagen at high concentrations 

much higher than exist in present urban 

atmospheres.408

Effects of ground-level smog causing 

intense eye irritation have been 

attributed to photochemical oxidants, 

including PAN.409 Animal toxicological 

information on the inhalation effects of 

the non-ozone oxidants has been limited 

to a few studies on PAN. Acute 

exposure to levels of PAN can cause 

changes in lung morphology, behavioral 

modifications, weight loss, and 

susceptibility to pulmonary infections. 

Human exposure studies indicate minor 

pulmonary function effects at high PAN 

concentrations, but large interindividual variability precludes 

definitive conclusions.410

i. Other Air Toxics 

In addition to the compounds 

described above, other compounds in 

gaseous hydrocarbon and PM emissions 

from vehicles will be affected by today’s 

proposed action. Mobile source air toxic 

compounds that will potentially be 

impacted include ethylbenzene, 

polycyclic organic matter, 

propionaldehyde, toluene, and xylene. 

Information regarding the health effects 

of these compounds can be found in 

EPA’s IRIS database.411

F. Environmental Effects of Criteria and 

Air Toxic Pollutants 

In this section we discuss some of the 

environmental effects of PM and its 

precursors, such as visibility 

impairment, atmospheric deposition, 

and materials damage and soiling, as 

well as environmental effects associated 

with the presence of ozone in the 

ambient air, such as impacts on plants, 

including trees, agronomic crops and 

urban ornamentals, and environmental 

effects associated with air toxics. 

1. Visibility 

Visibility can be defined as the degree 

to which the atmosphere is transparent 

to visible light.412 Airborne particles 

degrade visibility by scattering and 

absorbing light. Visibility is important 

because it has direct significance to 

people’s enjoyment of daily activities in 

all parts of the country. Individuals 

value good visibility for the well-being 

it provides them directly, where they 

live and work, and in places where they 

enjoy recreational opportunities. 

Visibility is also highly valued in 

natural areas such as national parks and 

wilderness areas and special emphasis 

is given to protecting visibility in these 

areas. For more information on visibility 

see the final 2004 PM AQCD as well as 

the 2005 PM Staff Paper.413 414

EPA is pursuing a two-part strategy to 

address visibility. First, to address the 

welfare effects of PM on visibility, EPA 

has set secondary PM2.5 standards 

which act in conjunction with the 

establishment of a regional haze 

program. In setting this secondary 

standard EPA has concluded that PM2.5

causes adverse effects on visibility in 

various locations, depending on PM 

concentrations and factors such as 

chemical composition and average 

relative humidity. Second, section 169 

of the Clean Air Act provides additional 

authority to address existing visibility 

impairment and prevent future visibility 

impairment in the 156 national parks, 

forests and wilderness areas categorized 

as mandatory class I federal areas (62 FR 

38680–81, July 18, 1997).415 In July 

1999 the regional haze rule (64 FR 

35714) was put in place to protect 

visibility in mandatory class I federal 

areas. Visibility can be said to be 

impaired in both PM2.5 nonattainment 

areas and mandatory class I federal 

areas. 

2. Atmospheric Deposition 

Wet and dry deposition of ambient 

particulate matter delivers a complex 

mixture of metals (e.g., mercury, zinc, 

lead, nickel, aluminum, cadmium), 

organic compounds (e.g., POM, dioxins, 

furans) and inorganic compounds (e.g., 

nitrate, sulfate) to terrestrial and aquatic 

ecosystems. The chemical form of the 

compounds deposited depends on a 

variety of factors including ambient 

conditions (e.g., temperature, humidity, 

oxidant levels) and the sources of the 

material. Chemical and physical 

transformations of the particulate 

compounds occur in the atmosphere as 

well as the media onto which they 

deposit. These transformations in turn 

influence the fate, bioavailability and 

potential toxicity of these compounds. 

Atmospheric deposition has been 

identified as a key component of the 

environmental and human health 

hazard posed by several pollutants 

including mercury, dioxin and PCBs.416

Adverse impacts on water quality can 

occur when atmospheric contaminants 

deposit to the water surface or when 

material deposited on the land enters a 

waterbody through runoff. Potential 

impacts of atmospheric deposition to 

waterbodies include those related to 

both nutrient and toxic inputs. Adverse 

effects to human health and welfare can 

occur from the addition of excess 

particulate nitrate nutrient enrichment, 

which contributes to toxic algae blooms 

and zones of depleted oxygen, which 

can lead to fish kills, frequently in 

coastal waters. Particles contaminated 

with heavy metals or other toxins may 

lead to the ingestion of contaminated 

fish, ingestion of contaminated water, 

damage to the marine ecology, and 

limits to recreational uses. Several 

studies have been conducted in U.S. 

coastal waters and in the Great Lakes 

Region in which the role of ambient PM 

deposition and runoff is 

25070 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

417U.S. EPA (2004) National Coastal Condition 

Report II. Office of Research and Development/ 

Office of Water. EPA–620/R–03/002. This document 

is available in Docket EPA–HQ–OAR–2005–0161. 

418 Gao, Y., E.D. Nelson, M.P. Field, et al. 2002. 

Characterization of atmospheric trace elements on 

PM2.5 particulate matter over the New York-New 

Jersey harbor estuary. Atmos. Environ. 36: 1077– 

1086. 

419 Kim, G., N. Hussain, J.R. Scudlark, and T.M. 

Church. 2000. Factors influencing the atmospheric 

depositional fluxes of stable Pb, 210Pb, and 7Be 

into Chesapeake Bay. J. Atmos. Chem. 36: 65–79. 

420Lu, R., R.P. Turco, K. Stolzenbach, et al. 2003. 

Dry deposition of airborne trace metals on the Los 

Angeles Basin and adjacent coastal waters. J. 

Geophys. Res. 108(D2, 4074): AAC 11–1 to 11–24. 

421 Marvin, C.H., M.N. Charlton, E.J. Reiner, et al. 

2002. Surficial sediment contamination in Lakes 

Erie and Ontario: A comparative analysis. J. Great 

Lakes Res. 28(3): 437–450. 

422 U.S. EPA (2005). Review of the National 

Ambient Air Quality Standards for Particulate 

Matter: Policy Assessment of Scientific and 

Technical Information, OAQPS Staff Paper. This 

document is available in Docket EPA–HQ–OAR– 

2005–0161. 

423Nouchi I, S Toyama. 1998. Effects of ozone 

and peroxyacetyl nitrate on polar lipids and fatty 

acids in leaves of morning glory and kidney bean. 

Plant Physiol. 87:638–646. 

424Oka E, Y Tagami, T Oohashi, N Kondo. 2004. 

A physiological and morphological study on the 

injury caused by exposure to the air pollutant, 

peroxyacetyl nitrate (PAN), based on the 

quantitative assessment of the injury. J Plant Res. 

117:27–36. 

425Sun E-J, M-H Huang. 1995. Detection of 

peroxyacetyl nitrate at phytotoxic level and its 

effects on vegetation in Taiwan. Atmos. Env. 

29:2899–2904. 

426 Koukol J, WM Dugger, Jr., RL Palmer. 1967. 

Inhibitory effect of peroxyacetyl nitrate on cyclic 

photophosphorylation by chloroplasts from black 

valentine bean leaves. Plant Physiol. 42:1419–1422. 

427Thompson CR, G Kats. 1975. Effects of 

ambient concentrations of peroxyacetyl nitrate on 

navel orange trees. Env. Sci. Technol. 9:35–38. 

428 Bytnerowicz A, ME Fenn. 1995. Nitrogen 

deposition in California forests: A Review. Environ. 

Pollut. 92:127–146. 

429U.S. EPA. 1991. Effects of organic chemicals 

in the atmosphere on terrestrial plants. EPA/600/3– 

91/001. 

430Cape JN, ID Leith, J Binnie, J Content, M 

Donkin, M Skewes, DN Price, AR Brown, AD 

Sharpe. 2003. Effects of VOCs on herbaceous plants 

in an open-top chamber experiment. Environ. 

Pollut. 124:341–343. 

investigated.417 418 419 420 421 In addition, 

the process of acidification affects both 

freshwater aquatic and terrestrial 

ecosystems. Acid deposition causes 

acidification of sensitive surface waters. 

The effects of acid deposition on aquatic 

systems depend largely upon the ability 

of the ecosystem to neutralize the 

additional acid. As acidity increases, 

aluminum leached from soils and 

sediments, flows into lakes and streams 

and can be toxic to both terrestrial and 

aquatic biota. The lower pH 

concentrations and higher aluminum 

levels resulting from acidification make 

it difficult for some fish and other 

aquatic organisms to survive, grow, and 

reproduce. 

Adverse impacts on soil chemistry 

and plant life have been observed for 

areas heavily influenced by atmospheric 

deposition of nutrients, metals and acid 

species, resulting in species shifts, loss 

of biodiversity, forest decline and 

damage to forest productivity. Potential 

impacts also include adverse effects to 

human health through ingestion of 

contaminated vegetation or livestock (as 

in the case for dioxin deposition), 

reduction in crop yield, and limited use 

of land due to contamination. Research 

on effects of acid deposition on forest 

ecosystems has come to focus 

increasingly on the biogeochemical 

processes that affect uptake, retention, 

and cycling of nutrients within these 

ecosystems. Decreases in available base 

cations from soils are at least partly 

attributable to acid deposition. Base 

cation depletion is a cause for concern 

because of the role these ions play in 

acid neutralization and because 

calcium, magnesium and potassium are 

essential nutrients for plant growth and 

physiology. Changes in the relative 

proportions of these nutrients, 

especially in comparison with 

aluminum concentrations, have been 

associated with declining forest health. 

The deposition of airborne particles 

can reduce the aesthetic appeal of 

buildings and culturally important 

articles through soiling and can 

contribute directly (or in conjunction 

with other pollutants) to structural 

damage by means of corrosion or 

erosion.422 Particles affect materials 

principally by promoting and 

accelerating the corrosion of metals, by 

degrading paints, and by deteriorating 

building materials such as concrete and 

limestone. Particles contribute to these 

effects because of their electrolytic, 

hygroscopic, and acidic properties and 

their ability to adsorb corrosive gases 

(principally sulfur dioxide). The rate of 

metal corrosion depends on a number of 

factors, including: The deposition rate 

and nature of the pollutant; the 

influence of the metal protective 

corrosion film; the amount of moisture 

present; variability in the 

electrochemical reactions; the presence 

and concentration of other surface 

electrolytes; and the orientation of the 

metal surface. 

3. Plant and Ecosystem Effects of Ozone 

Ozone contributes to many 

environmental effects, with impacts to 

plants and ecosystems being of most 

concern. Ozone can produce both acute 

and chronic injury in sensitive species 

depending on the concentration level 

and the duration of the exposure. Ozone 

effects also tend to accumulate over the 

growing season of the plant, so that even 

lower concentrations experienced for a 

longer duration have the potential to 

create chronic stress on vegetation. 

Ozone damage to plants includes visible 

injury to leaves and a reduction in food 

production through impaired 

photosynthesis, both of which can lead 

to reduced crop yields, forestry 

production, and use of sensitive 

ornamentals in landscaping. In addition, 

the reduced food production in plants 

and subsequent reduced root growth 

and storage below ground can result in 

other, more subtle plant and ecosystems 

impacts. These include increased 

susceptibility of plants to insect attack, 

disease, harsh weather, interspecies 

competition and overall decreased plant 

vigor. The adverse effects of ozone on 

forest and other natural vegetation can 

potentially lead to species shifts and 

loss from the affected ecosystems, 

resulting in a loss or reduction in 

associated ecosystem goods and 

services. Last, visible ozone injury to 

leaves can result in a loss of aesthetic 

value in areas of special scenic 

significance like national parks and 

wilderness areas. The final 2006 Ozone 

Air Quality Criteria Document presents 

more detailed information on ozone 

effects on vegetation and ecosystems. 

4. Welfare Effects of Air Toxics 

Fuel combustion emissions contribute 

to ambient levels of pollutants that 

contribute to adverse effects on 

vegetation. PAN is a well-established 

phytotoxicant causing visible injury to 

leaves that can appear as metallic 

glazing on the lower surface of leaves 

with some leafy vegetables exhibiting 

particular sensitivity (e.g., spinach, 

lettuce, chard).423 424 425 PAN has been 

demonstrated to inhibit photosynthetic 

and non-photosynthetic processes in 

plants and retard the growth of young 

navel orange trees.426 427 In addition to 

its oxidizing capability, PAN 

contributes nitrogen to forests and other 

vegetation via uptake as well as dry and 

wet deposition to surfaces. As noted in 

Section X, nitrogen deposition can lead 

to saturation of terrestrial ecosystems 

and research is needed to understand 

the impacts of excess nitrogen 

deposition experienced in some areas of 

the country on water quality and 

ecosystems.428

Volatile organic compounds (VOCs), 

some of which are considered air toxics, 

have long been suspected to play a role 

in vegetation damage.429 In laboratory 

experiments, a wide range of tolerance 

to VOCs has been observed.430

Decreases in harvested seed pod weight 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25071 

431Cape JN, ID Leith, J Binnie, J Content, M 

Donkin, M Skewes, DN Price, AR Brown, AD 

Sharpe. 2003. Effects of VOCs on herbaceous plants 

in an open-top chamber experiment. Environ. 

Pollut. 124:341–343. 432 Viskari E-L. 2000. Epicuticular wax of Norway 

spruce needles as indicator of traffic pollutant 

deposition. Water, Air, and Soil Pollut. 121:327– 

337. 433Ugrekhelidze D, F Korte, G Kvesitadze. 1997. 

Uptake and transformation of benzene and toluene 

by plant leaves. Ecotox. Environ. Safety 37:24–29. 

434 Kammerbauer H, H Selinger, R Rommelt, A 

Ziegler-Jons, D Knoppik, B Hock. 1987. Toxic 

components of motor vehicle emissions for the 

spruce Pciea abies. Environ. Pollut. 48:235–243. 

435 Kwaitkowski, J.R., Macon, A., Taylor, F., 

Johnston, D.B.; Industrial Crops and Products 23 

(2006) 288–296. 

436Shapouri, H., Gallagher, P.; USDA’s 2002 

Ethanol Cost-of-Production Survey (published July 

2005). 

437Projected fuel mix was taken from Mueller, S., 

Energy Research Center at the University of 

Chicago; An Analysis of the Projected Energy Use 

of Future Dry Mill Corn Ethanol Plants (2010– 

2030); cost estimates were derived from 

modifications to the USDA process models. We are 

aware that the cost impacts of CHP are likely 

overestimated here and will be revised in the final 

rulemaking. 

have been reported for the more 

sensitive plants, and some studies have 

reported effects on seed germination, 

flowering and fruit ripening. Effects of 

individual VOCs or their role in 

conjunction with other stressors (e.g., 

acidification, drought, temperature 

extremes) have not been well studied. In 

a recent study of a mixture of VOCs 

including ethanol and toluene on 

herbaceous plants, significant effects on 

seed production, leaf water content and 

photosynthetic efficiency were reported 

for some plant species.431

Research suggests an adverse impact 

of vehicle exhaust on plants, which has 

in some cases been attributed to 

aromatic compounds and in other cases 

to nitrogen oxides.432 433 434 The impacts 

of VOCs on plant reproduction may 

have long-term implications for 

biodiversity and survival of native 

species near major roadways. Most of 

the studies of the impacts of VOCs on 

vegetation have focused on short-term 

exposure and few studies have focused 

on long-term effects of VOCs on 

vegetation and the potential for 

metabolites of these compounds to 

affect herbivores or insects. 

VIII. Impacts on Cost of Renewable 

Fuels, Gasoline, and Diesel 

We have assessed the impacts of the 

renewable fuel volumes required by 

EISA on their costs and on the costs of 

the gasoline and diesel fuels into which 

the renewable fuels will be blended. 

More details of feedstock costs are 

addressed in Section X.A. 

A. Renewable Fuel Production Costs 

1. Ethanol Production Costs 

a. Corn Ethanol 

A significant amount of work has 

been done in the last decade surveying 

and modeling the costs involved in 

producing ethanol from corn in order to 

serve business and investment purposes 

as well as to try to educate energy policy 

decisions. Corn ethanol costs for our 

work were estimated using models 

developed and maintained by USDA. 

Their work has been described in a 

peer-reviewed journal paper on cost 

modeling of the dry-grind corn ethanol 

process, and compares well with cost 

information found in surveys of existing 

plants.435 436

For our policy case scenario, we used 

corn prices of $3.34/bu in 2022 with 

corresponding DDGS prices of $139.78/ 

ton (all 2006$). These estimates are 

taken from agricultural economics 

modeling work done for this proposal 

using the Forestry and Agricultural 

Sector Optimization Model (see Section 

IX.A). 

For natural gas-fired ethanol 

production producing dried co-product 

(currently describes the largest fraction 

of the industry), in the policy case corn 

feedstock minus DDGS sale credit 

represents about 57% of the final pergallon cost, while utilities, facility, and 

labor comprise about 22%, 11%, and 

4%, respectively. Thus, the cost of 

ethanol production is most sensitive to 

the prices of corn and the primary coproduct, DDGS, and relatively 

insensitive to economy of scale over the 

range of plant sizes typically seen (40– 

100 MMgal/yr). 

We expect that several process fuels 

will be used to produce corn ethanol 

(see DRIA Section 1.4), which are 

presented by their projected 2022 

volume production share in Table 

VIII.A.1–1a and cost impacts for each in 

Table VIII.A.1–1b.437 We request 

comment on the projected mix of plant 

fuel sources in the future as well as the 

cost impacts of various technologies. 

TABLE VIII.A.1–1a—PROJECTED 2022 BREAKDOWN OF FUEL TYPES USED TO ESTIMATE PRODUCTION COST OF CORN

ETHANOL, PERCENT SHARE OF TOTAL PRODUCTION VOLUME

Plant type 

Fuel type Total by 

plant type 

Biomass 

(percent) 

Coal 

(percent) 

Natural gas 

(percent) 

Biogas 

(percent) All fuels 

(percent) 

Coal/Biomass Boiler ............................................................. 11 0 ........................ ........................ 11 

Coal/Biomass Boiler + CHP ................................................ 10 4 ........................ ........................ 14 

Natural Gas Boiler ............................................................... ........................ ........................ 49 14 63 

Natural Gas Boiler + CHP ................................................... ........................ ........................ 12 ........................ 12 

Total by Fuel Type ........................................................ 21 4 61 14 100 

TABLE VIII.A.1–1b—PROJECTED 2022 BREAKDOWN OF COST IMPACTS BY FUEL TYPE USED IN ESTIMATING PRODUCTION

COST OF CORN ETHANOL, DOLLARS PER GALLON RELATIVE TO NATURAL GAS BASELINE

Plant type 

Fuel type Total by 

plant type 

Biomass a Coal Natural gas Biogas b

All fuels 

Coal/Biomass Boiler ............................................................. ¥$0.02 ¥$0.02 ........................ ........................ ........................

Coal/Biomass Boiler + CHP ................................................ +$0.14 +$0.14 ........................ ........................ ........................

Natural Gas Boiler ............................................................... ........................ ........................ baseline +$0.00 ........................

25072 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

438Capital costs for a natural gas fired plant were 

taken from USDA cost model; incremental costs to 

use coal as the primary energy source were derived 

from conversations with ethanol plant construction 

contractors. 

439Although some oil extraction may be done as 

front-end fractionation of the kernel, we believe the 

majority will be produced via separation from 

distillers’ grains streams. For more discussion of 

corn oil extraction and fractionation, see Chapter 4 

of the DRIA. 

TABLE VIII.A.1–1b—PROJECTED 2022 BREAKDOWN OF COST IMPACTS BY FUEL TYPE USED IN ESTIMATING PRODUCTION

COST OF CORN ETHANOL, DOLLARS PER GALLON RELATIVE TO NATURAL GAS BASELINE—Continued 

Plant type 

Fuel type Total by 

plant type 

Biomass a Coal Natural gas Biogas b

All fuels 

Natural Gas Boiler + CHP ................................................... ........................ ........................ +$0.16 ........................ ........................

Total by Fuel Type ........................................................ ........................ ........................ ........................ ........................ $0.04 

aAssumes biomass has same plant-delivered cost as coal. 

bAssumes biogas has same plant-delivered cost as natural gas. 

Based on energy prices from EIA’s 

Annual Energy Outlook (AEO) 2008 

baseline case ($53/bbl crude oil), we 

arrive at a production cost of $1.49/gal. 

In the case of EIA’s high price scenario 

($92/bbl crude), this figure increases by 

6 cents per gallon. More details on the 

ethanol production cost estimates can 

be found in Chapter 4 of the DRIA. This 

estimate represents the full cost to the 

plant operator, including purchase of 

feedstocks, energy required for 

operations, capital depreciation, labor, 

overhead, and denaturant, minus 

revenue from sale of co-products. The 

capital cost for a 65 MMgal/yr natural 

gas fired dry mill plant is estimated at 

$89MM (this the projected average size 

of such plants in 2022). Similarly, coal 

and biomass fired plants were assumed 

to be 110 MGY in capacity, with an 

estimated capital cost of $200MM.438

On average, ethanol produced in a 

facility using coal or biomass as a 

primary energy source results in a pergallon cost $0.02/gal lower compared to 

production using natural gas. 

In this cost estimation work, we did 

not assume any pelletizing of DDGS. 

Pelletizing is expected to improve ease 

of shipment to more distant markets, 

which may become more important at 

the larger volumes projected for the 

future. However, while many in 

industry are aware of this technology, 

those we spoke with are not employing 

it in their plants, and do not expect 

widespread use in the foreseeable 

future. According to USDA’s model, 

pelletizing adds $0.035/gal to the 

ethanol production cost. We request 

comment on whether pelletizing should 

be included in our program cost 

estimates. 

In support of our biodiesel and 

renewable diesel volume feasibility 

estimates, we included recovery of corn 

oil from distillers’ grains streams in our 

ethanol production cost estimates at a 

rate of 37% of ethanol production by 

2022.439 According to economic 

analyses done by USDA based on the GS 

Cleantech corn oil extraction process, 

the capital cost to install the system for 

a 50 MMgal/yr ethanol plant is 

approximately $6 million. The system is 

capable of extracting about one third of 

the corn oil entering the plant, and 

produces a low-quality corn oil coproduct stream. In our analysis, we 

assumed the value of this additional coproduct to be 70% that of soy oil (the 

same as yellow grease, $0.27/lb), 

resulting in a credit per gallon of 

ethanol of $0.04 for a 50 MMgal/yr plant 

operating such a system. 

Note that the ethanol production cost 

given here does not account for any 

subsidies on production or sale of 

ethanol, and is independent of the 

market price of ethanol. 

b. Cellulosic Ethanol 

i. Feedstock Costs 

Cellulosic Feedstock Costs 

To estimate the cost of producing 

cellulosic biofuels, it was first necessary 

to estimate the cost of harvesting, 

storing, processing and transporting the 

feedstocks to the biofuel production 

facilities. Ethanol or other cellulosic 

biofuels can be produced from crop 

residues such as corn stover, wheat, 

rice, oat, and barley straw, sugar cane 

bagasse, and sorghum, from other 

cellulosic plant matter such as forest 

thinnings and forest-fuel removal, 

pulping residues, and from the 

cellulosic portions of municipal solid 

waste (MSW). Currently, there are no 

energy crops such as switchgrass nor 

short rotation woody crops (SRWC 

poplars, etc.) grown specifically for 

energy production. 

Our feedstock supply analysis 

projected that crop residue, primarily 

corn stover, will be the most abundant 

of the cellulosic feedstocks, comprising 

about 61% of the total biomass 

feedstock inventory. Forest residues 

make up about 25% of the total, and 

MSW makes up the remaining 14%. At 

present, there are no commercial sized 

cellulosic ethanol plants in the U.S. 

Likewise, there are no commercially 

proven, fully-integrated feedstock 

supply systems dedicated to providing 

any of the feedstocks we mentioned to 

ethanol facilities of any size, although 

certain biomass is harvested for other 

purposes. For this reason, our feedstock 

cost estimates are projections and not 

based on any existing market data. 

Our feedstock costs include an 

additional preprocessing cost that many 

other feedstock cost estimates do not 

include—thus our costs may seem 

higher. We used biofuel plant cost 

estimates provided by NREL which no 

longer includes the cost for finely 

grinding the feedstock prior to feeding 

it to the biofuel plant. Thus, our 

feedstock costs include an $11 per dry 

ton cost to account for the costs of this 

grinding operation, regardless of 

whether this operation occurs in the 

field or at the plant gate. 

Crop Residue and Energy Crops 

Crop residue harvest is currently a 

secondary harvest; that is they are 

harvested or gathered only after the 

prime crop has been harvested. In most 

northern areas, the harvest periods will 

be short due to the onset of winter 

weather. In some cases, it may be 

necessary to gather a full year’s worth of 

residue within just a few weeks. 

Consequently, to accomplish this 

hundreds of pieces of farm equipment 

will be required for a few weeks each 

year to complete a harvest. Winter 

conditions in the South make it 

somewhat easier to extend the harvest 

periods; in some cases, it may be 

possible to harvest a residue on an as 

needed basis. 

During the corn grain harvest, 

generally only the cob and the leaves 

above the cob are taken into the 

harvester. Thus, the stover harvest 

would likely require some portion of the 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25073 

440Personal Communication, Eini C. Lowell, 

Research Scientist, USDA Forest Service. 

standing-stalks be mowed or shredded, 

following which the entire residue, 

including that discharged from the 

combine residue-spreader, would need 

to be raked. Balers, likely a mix of large 

round and large square balers, would 

follow the rakes. The bales would then 

be removed from the field, usually to 

the field-side in the first operation of the 

actual harvest, following which they 

would then be hauled to a satellite 

facility for intermediate storage. For our 

analysis we assumed that bales would 

then be hauled by truck and trailer to 

the processing plant on an as needed 

basis. 

The small grain straws (wheat, rice, 

oats, barley, sorghum) are cut near the 

ground at the time of grain harvest and 

thus likely won’t require further 

mowing or shredding. They will likely 

need to be raked into a windrow prior 

to baling. Because small grain straws 

have been baled and stored for many 

years, we don’t expect unusual 

requirements for handling these 

residues. Their harvest and storage costs 

will likely be less than those for corn 

stover, but their overall quantity is 

much less than corn stover (corn stover 

makes up about 71% of all the crop 

residues), so we don’t expect their lower 

costs to have, individually or 

collectively, a huge effect on the overall 

feedstock costs. Thus, we project that 

for several years, the feedstock costs 

will be largely a function of the cost to 

harvest, store, and haul corn stover. 

For the crop residues, we relied on 

the FASOM agricultural cost model for 

farm harvesting and collection costs. 

FASOM estimates it would cost $33 per 

dry ton to mow, rake, bale, and field 

haul the bales and replace nutrients. We 

added $10 per dry ton as a farmer 

payment, which we believe is a 

necessary reimbursement to farmers to 

cover their costs associated with this 

additional harvest. Thus, $43 per dry 

ton covers the cost of making the crop 

residue available at the farm gate. This 

farm gate cost could be lower if new 

equipment is developed that would 

allow the farmer to harvest the corn 

stover at the same time as the corn. We 

also conducted our own independent 

analysis of the farm gate feedstock costs 

for corn stover, and our farm gate cost 

estimate for stover feedstock is very 

similar to FASOM’s. For the steps 

involved in moving the corn stover from 

the farm gate to the cellulosic ethanol 

plant, we relied upon our own cost 

analysis. Our cost analysis estimates 

that an additional $32 per dry ton 

would be required to haul the bales to 

satellite storage, pay for the storage 

facilities, and grind the residue. Because 

of the low density of corn stover and 

other crop residues, we estimate that 60 

or more secondary storage sites would 

be necessary to minimize the combined 

transportation and storage costs for a 

100 million gallon per year plant. We 

estimated it would cost about $14 per 

dry ton to haul the feedstock from the 

satellite storage to the processing plant. 

Adding up all the costs, corn stover is 

estimated to cost $88 per dry ton 

delivered to the cellulosic biofuel plant. 

A more detailed discussion of our corn 

stover feedstock cost analysis is 

contained in Chapter 4.1 of the DRIA. 

Energy crops such as switchgrass and 

miscanthus would be harvested, baled, 

stored and transported very similar to 

crop residues. Because of their higher 

production density per acre, though, we 

would expect that the ‘‘farm gate’’ costs 

to be slightly lower than crop residues 

(we estimate the costs to be about $1 per 

dry ton lower). Also, the higher 

production density would allow for 

fewer secondary storage facilities 

compared to crop residue and a shorter 

transportation distance. For example, 

we estimate that switchgrass would 

require less than 30 secondary storage 

facilities which would help to lower the 

feedstock costs for a 100 million gallon 

per year plant compared to crop 

residues. As a result the secondary 

storage and transportation costs are 

estimated to be $9 per ton lower than 

crop residue such as corn stover. Thus, 

we estimate that cellulosic feedstock 

costs sourced from switchgrass would 

be about $78 per dry ton. Chapter 4.1 of 

the DRIA contains a more in-depth 

discussion of the feedstock costs for 

energy crops such as switchgrass. 

Forestry Residue 

Harvest and transport costs for woody 

biomass in its different forms vary due 

to tract size, tree species, volumes 

removed, distance to the wood-using/ 

storage facility, terrain, road condition, 

and other many other considerations. 

There is a significant variation in these 

factors within the United States, so 

timber harvest and delivery systems 

must be designed to meet constraints at 

the local level. Harvesting costs also 

depend on the type of equipment used, 

season in which the operation occurs, 

along with a host of other factors. Much 

of the forest residue is already being 

harvested by logging operations, or is 

available from milling operations. 

However, the smaller branches and 

smaller trees proposed to be used for 

biofuel production are not collected for 

their lumber so they are normally left 

behind. Thus, this forest residue would 

have to be collected and transported out 

of the forest, and then most likely 

chipped before transport to the biofuel 

plant. 

In general, most operators in the near 

future would be expected to chip at 

roadside in the forest, blowing the chips 

directly into a chip van. When the van 

is full it will be hauled to an end user’s 

facility and a new van will be moved 

into position at the chipper. The process 

might change in the future as baling 

systems become economically feasible 

or as roll-off containers are proven as a 

way to handle logging slash. At present, 

most of the chipping for biomass 

production is done in connection with 

forest thinning treatments as part of a 

forest fire prevention strategy. The 

major problem associated with 

collecting logging residues and biomass 

from small trees is handling the material 

in the forest before it gets to the chipper. 

Specially-built balers and roll-off 

containers offer some promise to reduce 

this cost. Whether the material is 

collected from a forest thinning 

operation or a commercial logging 

operation, chips from residues will be 

dirty and will require screening or some 

type of filtration at the end-user’s 

facility.440

Results from a study in South Georgia 

show that under the right conditions, a 

small chipper could be added to a larger 

operation to obtain additional chip 

production without adversely impacting 

roundwood production, and that the 

chips could be produced from limbs and 

tops of harvested trees at costs ranging 

from $11 per ton and up. Harvesting 

understory (the layer formed by grasses, 

shrubs, and small trees under the 

canopy of larger trees and plants) for use 

in making fuel chips was estimated to 

be about $1 per ton more expensive. 

Per-ton costs decrease as the volume 

chipped increases per acre. Some 

estimates suggest that if no more than 10 

loads of roundwood are produced before 

a load of chips is made, that chippermodified system could break even. Cost 

projections suggest that removing only 

limbs and tops may be marginal in 

terms of cost since one load of chips is 

produced for about every 15 loads of 

roundwood. 

Instead of conducting our own 

detailed cost estimate for making forest 

residue chips available at the edge of the 

harvested forests, we instead relied 

upon the expertise of the U.S. Forest 

Service. The U.S. Forest Service 

provided us a cost curve for different 

categories of forest residue, including 

logging residue, other removals (i.e., 

clearing trees for new building 

construction), timberland trimmings 

25074 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

441Ashton, S.; B. Jackson; R. Schroeder. Cost 

Factors in Harvesting and Transporting Woody 

Biomass, 2007. Module 4: Introduction to 

Harvesting, Transportation, and Processing:: Fact 

Sheet 4.7. 

442We plan on conducting a more thorough 

analysis of tipping fees by waste type for the final 

rulemaking. 

(forest fire prevention strategy) and mill 

residues. They recommended that we 

choose $45 per dry ton as the price 

point for our cost analysis. This seemed 

reasonable since this price point was 

roughly the same as the farm gate crop 

residue discussed above, and so we 

used this price point for our analysis. 

Assuming that the wood chips would be 

ground further in the field adds an 

additional $11 per dry ton to the 

feedstock cost. 

Delivery of woody biomass from the 

harvesting site to a conversion facility, 

like delivery of more conventional forest 

products, accounts for a significant 

portion of the delivered cost. In fact, 

transportation of wood fiber (including 

hauling within the forest) accounts for 

about 25 to 50% of the total delivered 

costs and highly depends on fuel prices, 

haul distance, material moisture 

content, and vehicle capacity and 

utilization. Also, beyond a certain 

distance, transportation becomes the 

limiting factor and the costs become 

directly proportional to haul 

distance.441 Based on our own cost 

analysis, we anticipate that hauling 

woody biomass to plant will cost about 

$14 per ton, for a total delivered price 

of about $70 per dry ton. Chapter 4.1 of 

the DRIA contains a more detailed 

discussion on the feedstock costs for 

forest residue. 

Municipal Solid Waste 

Millions of tons of municipal solid 

waste (MSW) continue to be disposed of 

in landfills across the country, despite 

recent large gains in waste reduction 

and diversion. The biomass fraction of 

this total stream represents a potentially 

significant resource for renewable 

energy (including electricity and 

biofuels). Because this waste material is 

already being generated, collected and 

transported (it would only need to be 

transported to a different location), its 

use is likely to be less expensive than 

other cellulosic feedstocks. One 

important difficulty facing those who 

plan to use MSW fractions for fuel 

production is that in many places, even 

today, MSW is a mixture of all types of 

wastes, including biomaterials such as 

animal fats and grease, tin, iron, 

aluminum, and other metals, painted 

woods, plastics, and glass. Many of 

these materials can’t be used in 

biochemical and thermochemical 

ethanol production, and, in fact, would 

inflate the transportation costs, impede 

the operations at the cellulosic ethanol 

plant and cause an expensive waste 

stream for biofuel producers. 

Thus, accessing sorted MSW would 

likely be a requirement for firms 

planning on using MSW for producing 

cellulosic biofuels. In a confidential 

conversation, a potential producer who 

plans to use MSW to produce ethanol 

indicated that their plant plans are 

based on obtaining cellulosic biowaste 

which has already been sorted at the 

waste source (e.g., at the curbside, 

where the refuse hauler picks up waste 

already sorted by the generating homeowner or business). For example, in a 

tract of homes, one refuse truck would 

pick up glass, plastic, and perhaps other 

types of waste destined for a specific 

disposal depot, whereas a different 

truck would follow to pick up wood, 

paper, and other cellulosic materials to 

be hauled to a depot that supplies an 

ethanol plant. However, only a small 

fraction of the MSW generated today is 

sorted at the curbside. 

Another alternative would be to sort 

the waste either at a sorting facility, or 

at the landfill, prior to dumping. There 

are two prominent options here. The 

first is that there is no sorting at the 

waste creation site, the home or 

business, and thus a single waste stream 

must be sorted at the facility. This 

operation would likely be done by hand 

or by automated equipment at the 

facility. To do so by hand is very labor 

intensive and somewhat slower than 

using an automated system. In most 

cases the ‘by-hand’ system produces a 

slightly cleaner stream, but the high cost 

of labor usually makes the automated 

system more cost-effective. Perhaps the 

best approach for low cost and a clean 

stream is the combination of hand 

sorting with automated sorting. 

The third option is a combination of 

the two which requires that there is at 

least some sorting at the home or 

business which helps to prevent 

contamination of the waste material, but 

then the final sorting occurs 

downstream at a sorting site, or at the 

landfill. 

We have little data and few estimates 

for the cost to sort MSW. One estimate 

generated by our Office of Solid Waste 

for a combination of mechanically and 

manually sorting a single waste stream 

downstream of where the waste is 

generated puts the cost in the $20 to $30 

per ton range. There is a risk, though, 

that the waste stream could still be 

contaminated and this would increase 

the cost of both transporting the 

material and using this material at the 

biofuel plant due to the toxic ash 

produced which would require disposal 

at a toxic waste facility. If a less 

contaminated stream is desired it would 

probably require sorting at the 

generation site—the home or business— 

which would likely be more costly since 

many more people in society would 

then have to be involved and special 

trucks would need to be used. Also, 

widespread participation is difficult 

when a change in human behavior is 

required as some may not be so willing 

to participate. Offering incentives could 

help to speed the transition to curbside 

recycling (i.e., charging a fee for 

nonsorted waste, or paying a small 

amount for sorted tree trimmings and 

construction and demolition waste). 

Assuming that curbside sorting is 

involved, at least in a minor way, total 

sorting costs might be in the $30 to $40 

per ton range. We request comment on 

the costs incurred for sorting cellulosic 

material from the rest of MSW waste. 

These sorting costs would be offset by 

the cost savings for not disposing of the 

waste material. Most landfills charge 

tipping fees, the cost to dump a load of 

waste into a landfill. In the United 

States, the national average nominal 

tipping fee increased fourfold from 1985 

to 2000. The real tipping fee almost 

doubled, up from a national average (in 

1997 dollars) of about $12 per ton in 

1985 to just over $30 in 2000. Equally 

important, it is apparent that the tipping 

fees are much higher in densely 

populated regions and for areas along 

the U.S. coast. For example, in 2004, the 

tipping fees were $9 per ton in Denver 

and $97 per ton in Spokane. Statewide 

averages also varied widely, from $8 a 

ton in New Mexico to $75 in New 

Jersey. Tipping fees ranged from $21 to 

98 per ton in 2006 for MSW and $18/ 

ton to $120/ton for construction and 

demolition waste. It is likely that the 

tipping fees are highest for 

contaminated waste that requires the 

disposal of the waste in more expensive 

waste sites that can accept the 

contaminated waste as opposed to a 

composting site. However, this same 

contaminated material would probably 

not be desirable to biofuel producers. 

Presuming that only the 

noncontaminated cellulosic waste (yard 

trimmings, building construction and 

demolition waste and some paper) is 

collected as feedstocks for biofuel 

plants, the handling and tipping fees are 

likely much lower, in the $30 per ton 

range.442

The avoidance of tipping fees, 

however, is a complex issue since 

landfills are generally not owned by 

municipalities anymore. Both large and 

small municipalities recognized their 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25075 

443Osamu Sakamoto, The Financial Feasibility 

Analysis of Municipal Solid Waste to Ethanol 

Conversion, Michigan State University, Plan B 

Master Research Paper in partial fulfillment of the 

requirement for the degree of Master of Science, 

Department of Agricultural Economics, 2004 

444Breaking the Biological Barriers to Cellulosic 

Ethanol: A Joint Research Agenda, A Research 

Roadmap Resulting from the Biomass to Biofuels 

Workshop Sponsored by the U.S. Department of 

Energy, December 7–9, 2005, Rockville, Maryland; 

DOE/SC–0095, Publication Date: June 2006 

inability to handle the new and complex 

solid waste regulations at a reasonable 

cost. Only 38 out of the 100 largest cities 

own their own landfills. To deal with 

the solid waste, large private companies 

built massive amounts of landfill 

capacity. The economic incentive is for 

private landfill operators to fill their 

landfills with garbage as early as 

possible to pay off their capital 

investment (landfill site) quickly. Also, 

the longer the landfill is operating the 

greater is its exposure to liability due to 

leakages and leaching. Furthermore, 

landfills can more cost-effectively 

manage the waste as the scale of the 

landfill is enlarged. As a result, there are 

fewer landfills and landfill owners, and 

an expansion of market share by large 

private waste management firms, thus 

decreasing the leverage a biofuel 

producer may have.443 Many waste 

management firms have been proactive 

by using the waste material to produce 

biogas, another fuel type that would 

qualify under RFS2. Yet other parties 

interested in procuring MSW are wasteto-energy (WTE) facilities, which burn 

as much waste material as possible to 

produce electricity. These three 

different interests may compete for 

MSW for producing biofuels. This 

competition is desirable, resulting in 

lower overall cost and the production of 

the most cost-effective types of biofuels. 

We request comment on the costs 

avoided for diverting cellulosic material 

from landfills. 

Once the cellulosic biomass has been 

sorted from the rest of MSW, it would 

have to be transported to the biofuels 

plant. Transporting is different for MSW 

biomass compared to forest and crop 

residues. Forest and crop residues are 

collected from forests and farms, which 

are both rural sites, and transported to 

the biofuel plant which likely is located 

at a rural site. The trucks which 

transport the forest and crop residues 

can be large over-the-road trucks which 

can average moderate speeds because of 

the lower amount of traffic that they 

experience. Conversely, MSW is being 

collected throughout urban areas and 

would have to transported through 

those urban areas to the plant site. If the 

cellulosic biomass is being collected at 

curbside, it would likely be collected in 

more conventional refuse trucks. If the 

plant is nearby, then the refuse trucks 

could transport the cellulosic biomass 

directly to the plant. However, if the 

plant is located far away from a portion 

of the urban area, then the refuse trucks 

would probably have to be offloaded to 

more conventional over-the-road trucks 

with sizable trailers to make transport 

more cost-effective. We estimate that the 

cost to transport the cellulosic biomass 

sourced from MSW to the biofuel plant 

be $15 per ton. 

A significant advantage of MSW over 

other cellulosic biomass is that it can be 

generated year-round in many parts of 

the U.S. If a steady enough stream of 

this material is available, then 

secondary storage would not be 

necessary, thus avoiding the need to 

install secondary storage. We assumed 

that no secondary storage costs would 

be incurred for MSW-sourced cellulosic 

biomass. 

The total costs for MSW-sourced 

cellulosic biomass is estimated to be $30 

¥$40 per ton for sorting costs, a savings 

of $30 per ton for tipping costs avoided, 

$15 per ton for transportation costs and 

$11 per ton for grinding the cellulose to 

prepare it as a feedstock—resulting in a 

total feedstock cost of $26 to $36 per 

ton. In our cost analysis, we assumed an 

average cost of $31 per ton. Chapter 4.1 

of the DRIA contains a more detailed 

discussion of the feedstock costs for 

MSW. 

Table VIII.A.1–2 below summarizes 

major cost components for each 

cellulosic feedstock. 

TABLE VIII.A.1–2—SUMMARY OF CELLULOSIC FEEDSTOCK COSTS

[$53/ton crude oil costs] 

Ag residue Switchgrass Forest residue MSW 

60% of total feedstock 1% of total feedstock 25% of total feedstock 14% of total feedstock 

Mowing, Raking, Baling, Hauling, 

Nutrients and Farmer Payment 

$43/ton.

Mowing, Raking, Baling, Hauling, 

Nutrients and Farmer Payment 

$42/ton.

Harvesting, Hauling to Forest 

Edge, Chipping $45/ton.

Sorting, Contaminant Removal, 

Tipping Fees Avoided $0–$10/ 

ton. 

Hauling to Secondary Storage, 

Secondary Storage, Hauling to 

Plant $45/ton.

Hauling to Secondary Storage, 

Secondary Storage, Hauling to 

Plant $37/ton.

Grinding, Hauling to Plant $25/ton Grinding, Hauling to Plant $26/ 

ton. 

Total $88/ton ........................... Total $77/ton ................................. Total $70/ton ................................. Total Avg $31/ton. 

Weighting the cellulosic feedstock 

costs by their supply quantities results 

in an average cellulosic feedstock cost of 

$71 per ton which we used at the 

reference crude oil price of $53/bbl. We 

estimate that this average cost increases 

to $76 per ton at the high crude oil price 

of $92/bbl due to more expensive 

harvesting and transportation costs. 

ii. Production Costs 

In this section, we discuss the cost to 

biochemically and thermochemically 

convert cellulosic feedstocks into fuel 

ethanol. At a DOE sponsored workshop 

in 2005, a DOE biochemical expert 

commented that the challenges of 

converting cellulosic biomass to ethanol 

are very closely linked to solving the 

problems associated with both the 

hydrolysis and the fermentation of the 

carbohydrates in the feedstocks. He then 

stated that the resistance of cellulosic 

feedstock to bioprocessing will remain 

the central problem and will likely be 

the limiting factor in creating an 

economy based on cellulosic ethanol 

production.444

Notwithstanding the fact that all 

cellulosic biomass is made up of some 

combination of cellulose, hemicellulose, 

lignin, and trace amounts of other 

organic and inorganic chemicals and 

minerals, there are significant 

differences among the molecular 

structures of different plants. For 

example, a corn stalk is relatively 

lighter, more porous, and much more 

flexible than a tree branch of similar 

diameter. The tree branch (in most 

cases) is harder or denser and less 

porous throughout the stem and the 

25076 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

445A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. 

Neeves, J. Sheehan, and B. Wallace, National 

Renewable Energy Laboratory (NREL); L. Montague, 

A. Slayton, and J. Lukas Harris Group, Seattle, 

Washington, Ethanol Process Design and 

Economics Utilizing Co-Current Dilute Acid 

Prehydrolysis and Enzymatic Hydrolysis for Corn 

Stover; June 2002; NREL is a U.S. Department of 

Energy Laboratory operated by Midwest Research 

Institute • Battelle • Bechtel; Contract No. DE– 

AC36–99–GO10337. 

446Lin Wei, Graduate Research Assistant, Lester 

O. Pordesimo, Assistant Professor, Willam D. 

Batchelor, Professor, Department of Agricultural 

and Biological Engineering, Mississippi State 

University, MS 39762, USA, Ethanol Production 

from Wood: Comparison of Hydrolysis 

Fermentation and Gasification Biosynthesis, Paper 

Number: 076036, Written for presentation at the 

2007 ASABE Annual International Meeting. 

Minneapolis Convention Center, Minneapolis, MN, 

17–20 June 2007. 

447Hans P. Blaschek, Professor and Thaddeus C. 

Ezeji, Research Assistant, Department of Food 

Science and Human Nutrition, University of 

Illinois, Urbana-Champaign. Science of Alternative 

Feedstocks. 

448 Glossary of Biomass Terms, National 

Renewable Energy Laboratory, Golden, CO. http:// 

www.nrel.gov/biomass/glossary.html. 

outside or bark is less permeable and 

flexible. 

These differences among the 

cellulosic feedstock plant structures, 

e.g., density, rigidity, hardness, etc., 

suggest that different conversion 

processes, namely biochemical and 

thermochemical may be necessary to 

convert into ethanol as much of the 

available plant material as possible. For 

example, if wood chips, e.g., poplar 

trees, are to be treated biochemically, 

the chips must be reduced in size to 1- 

mm or less in order to increase the 

surface area for contact with acid, 

enzymes, etc. Breaking up a 5-in stem to 

such small pieces would consume a 

large amount of energy. On the other 

hand, processing corn stover into 

cellulosic ethanol has a maximum size 

of up to 1.5 inches (28 millimeters) in 

length because corn stover is so thin.445

By comparison, the particle size 

requirement for a thermochemical 

process is around 10-mm to 100-mm in 

diameter.446 Because of this, we believe 

feedstocks such as corn stover, wheat 

and rice straw, and switchgrass will 

likely be feedstocks for biochemical 

processes. Biochemical plants will 

likely be constructed in those areas of 

the country where these feedstocks are 

most abundant, e.g., the corn belt and 

upper Midwest. On the other hand, 

thermochemical plants will likely be 

constructed in those areas of the country 

where forest thinnings, forest fuelremoval operations, lumber production, 

and paper mills are most predominant, 

e.g., the South. Thermochemical or 

gasification units could be constructed 

near starch or biochemical cellulosic 

plants in order to take advantage of 

byproduct streams. We expect 

switchgrass (SG) will preferentially be 

fed to biochemical units since it is 

similar to straw, whereas short-rotation 

woody crops (SRWC) such as willows or 

poplars will preferentially be fed to 

thermochemical units. 

Biochemically, it is much more 

difficult to convert cellulosic plant 

matter into ethanol than it is to convert 

the starch from corn grain into ethanol. 

Corn starch consists of long 

polysaccharide chains that are weakly 

attracted to each other, quite flexible, 

and tend to curl up to form tiny particlelike bundles. This loose, flexible 

structure permits water and water-borne 

hydrolyzing enzymes to easily penetrate 

the polymer during the process stage 

known as hydrolysis. Once hydrolyzed, 

the corn starch sugar residues are easily 

fermentable. 

The hydrolysis of cellulosic biomass 

is much more challenging. Unlike 

starch, cellulosic plant matter is made 

up of three main constituents: Cellulose, 

hemicellulose, lignin, and minor 

amounts of various other organic and 

inorganic chemicals. 

Cellulose, the major constituent, is a 

polymer made up of only b-linked 

glucose monosaccharides. This 

molecular arrangement allows intramolecular hydrogen bonds to develop 

within each monomer and intermolecular hydrogen bonds to develop 

between adjacent polymers to form 

tight, rigid, strong, mostly straight 

polymer bundles that are insoluble in 

water and resistant to chemical attack. 

The net result of the structural 

characteristics makes cellulose much 

more difficult to hydrolyze than is 

hemicellulose. 

Hemicellulose contributes 

significantly to the total fermentable 

sugars of the lignocellulosic biomass. 

Unlike cellulose, hemicellulose is 

chemically heterogeneous and highly 

substituted. Compared to cellulose, this 

branching renders it amorphous and 

relatively easy to hydrolyze to its 

constituent sugars.447

Lignin, the third principle 

component, is a complex, cross-linked 

polymeric, high molecular weight 

substance derived principally from 

coniferyl alcohol by extensive 

condensation polymerization. While 

cellulose and hemicellulose contribute 

to the amount of fermentable sugars for 

ethanol production, lignin is not so 

readily digestable, but can be combusted 

to provide process energy in a 

biochemical plant or used as feedstock 

to a thermochemical process.448

Because of the complexities in 

digesting cellulosic biomass, the 

residence time is longer to digest the 

cellulose and perform the fermentation. 

Thus, the cellulosic plant capital costs 

are higher than those of corn (starch) 

ethanol plants. However, because corn 

is a food source with an intrinsic food 

value, corn ethanol’s feedstock costs are 

almost two times higher per ton (more 

than two times higher in the case for 

cellulose from MSW) than the 

feedstocks of a cellulosic ethanol plant. 

It is conceivable that depending on the 

cellulosic plant technology which 

drives its capital and operating costs 

that cellulosic ethanol plants’ lower 

feedstock costs could offset its higher 

capital costs resulting in lower 

production costs than corn-based 

ethanol. 

The National Renewable Energy 

Laboratory has been evaluating the state 

of biochemical cellulosic plant 

technology over the past decade or so, 

and it has identified principal areas for 

improvement. In 1999, it released its 

first report on the likely design concept 

for an nth generation biochemical 

cellulosic ethanol plant which projected 

the state of technology in some future 

year after the improvements were 

adopted. In 2002, NREL released a 

follow-up report which delved deeper 

into biochemical plant design in areas 

that it had identified in the 1999 report 

as deserving for additional research. 

Again, the 2002 report estimated the 

ethanol production cost for an nth 

generation biochemical cellulosic 

ethanol plant. These reports not only 

helped to inform policy makers on the 

likely capability and cost for 

biochemically converting cellulose to 

ethanol, but it helped to inform 

biochemical technology researchers on 

the most likely technology 

improvements that could be 

incorporated into these plant designs. 

To comply with the RFS 2 

requirements, NREL assessed the likely 

state of biochemical cellulosic plant 

technology over the years that the RFS 

standard is being phased in. The 

specific years assessed by NREL were 

2010, 2015 and 2022. The year 2010 

technology essentially represents the 

status of today’s biochemical cellulosic 

plants. The year 2015 technology 

captures the expected near-term 

improvements including the rapid 

improvements being made in enzyme 

technology. The year 2022 technology 

captures the cost of mature biochemical 

cellulosic plant technology. Table 

VIII.A.1–3 summarizes NREL’s 

estimated and projected production 

costs for biochemical cellulosic ethanol 

plant technology in these three years 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25077 

449Purdue yeast makes ethanol from agricultural 

waste more effectively, Purdue News, June 28, 2004 

http://www.purdue.edu/UNS/html4ever/2004/ 

040628.Ho.ethanol.html. 

450 GENENCOR LAUNCHES FIRST EVER 

COMMERCIAL ENZYME PRODUCT FOR 

CELLULOSIC ETHANOL, ROCHESTER, NY, WorldWire, October 22, 2007 Copyright© 2007. All rights 

reserved. World-Wire is a resource provided by 

Environment News Service. http://world-wire.com/ 

news/0710220001.html. 

451Ali Mohagheghi, Kent Evans, Yat-Chen Chou, 

and Min Zhang, Biotechnology Division for Fuels 

and Chemicals, National Renewable Energy 

Laboratory, Golden, CO 80401, Co-fermentation of 

Glucose, Xylose, and Arabinose by Genomic DNA– 

Integrated Xylose/Arabinose Fermenting Strain of 

Zymomonas mobilis AX101, Applied Biochemistry 

and Biotechnology Vols. 98–100, 2002, Copyright© 

2002 by Humana Press Inc., All rights of any nature 

whatsoever reserved. 

452NREL has authored a thermochemical report: 

Phillips, S Thermochemical Ethanol via Indirect 

Gasification and Mixed Alcohol Synthesis of 

Lignocellulosic Biomass; April, 2007, which does 

provide a cost estimate. However, this report only 

hypothesized how a thermochemical ethanol plant 

could achieve production costs at $1 per gallon, and 

Continued 

reflecting our average feedstock costs and adjusting the capital costs to a 7 

percent before tax rate of return. 

TABLE VIII.A.1–3—BIOCHEMICAL CELLULOSIC ETHANOL PRODUCTION COSTS PROVIDED BY NREL 

Year technology ............................................................... 2010 2015 2022 

Plant Size MMgal/yr ......................................................... 56 69 71 

Capital Cost $MM ............................................................ 232 220 199 

$MM/yr c/gal $MM/yr c/gal $MM/yr c/gal 

Capital Cost 7% ROI before taxes .................................. 25 46 24 35 22 31 

Fixed Costs ...................................................................... 9 16 9 12 8 12 

Feedstock Cost ................................................................ 55 99 55 79 55 77 

Other raw matl. costs ....................................................... 17 30 4 5 16 16 

Enzyme Cost .................................................................... 18 32 7 10 5 8 

Enzyme nutrients ............................................................. 8 14 2 3 2 2 

Electricity .......................................................................... ¥6 ¥10 ¥7 ¥9 ¥12 ¥16 

Waste disposal ................................................................. 1 2 3 4 1 1 

Total Costs ................................................................ 127 229 96 139 84 131 

NREL’s projected improvements in 

production costs over time are based on 

improved reaction biochemistry. Before 

discussing the expected improvements 

in the reaction biochemistry, we will 

discuss the reaction pathway for 

cellulosic biochemical. 

There are two primary reaction steps 

in a biochemical cellulosic ethanol 

plant. The first is hydrolysis. Hydrolysis 

breaks the polysaccharides into their 

sugar residues. The pretreated slurry is 

fed to a hydrolysis reactor; there may be 

multiple reactors, depending on the 

desired production rate. Dilute sulfuric 

acid is used to hydrolyze, primarily, the 

hemicellulose polysaccharides, xylan, 

mannan, arabinan, and galactan, to 

produce the mixed sugars. Very little of 

the cellulose polysaccharide, glucan, is 

hydrolyzed. 

The second is saccharification and cofermentation. Using a cellulase enzyme 

cocktail, saccharification of the 

cellulose to glucose occurs first at an 

elevated temperature to take advantage 

of increased enzyme activity, which 

reduces the quantity of required enzyme 

as well as the reaction time. Following 

cellulose saccharification, both the 

glucose and xylose sugars are cofermented. Although xylan, the 

hemicellulose polysaccharide, is more 

easily hydrolyzed than glucan (cellulose 

polysaccharides), the xylose sugar is 

more difficult to ferment than the 

glucose sugar. Different microbes as 

well as different residence times and 

process conditions are required for each. 

Therefore, it may be necessary to 

separate the glucose and xylose 

monomers before fermentation. 

Because xylan can make up as much 

as 25% of plant matter it is imperative 

that most of be available for ethanol 

production; the economic viability of 

biochemically produced ethanol 

depends heavily it. Good progress has 

been toward that end during the past 

few years.449

Also during the past few years, 

researchers have been developing ways 

to combine saccharification and 

fermentation into a single step through 

the use of enzyme/microbe cocktails. 

DOE and the National Renewable 

Energy Laboratory (NREL) have also 

supported research into more efficient, 

less costly enzymes for SSF. With their 

support, a less expensive, more efficient 

enzyme cocktail for cellulosic biomass 

fermentation has been developed.450

Others have also reported some success 

in co-fermenting glucose and xylose.451

As the biochemical enzymatic 

pathway is streamlined using more costeffective enzymes, and as these enzymes 

can more comprehensively saccarify 

and ferment the cellulose, the 

conversion fraction of the cellulose to 

ethanol will increase and the conversion 

time will decrease. An important benefit 

for these efficiency improvements is 

that the number and size of reaction 

vessels decrease, leading to lower 

capital costs and lower fixed operating 

costs. It is also estimated that less 

nutrients would be needed to maintain 

the enzymes reactivity. Because the 

production volume of ethanol will 

increase relative to the quantity of 

feedstock, it lowers the operating costs 

per gallon of ethanol. Between these 

various effects, the per-gallon costs for 

producing cellulosic ethanol through 

the biochemical pathway are expected 

to decrease dramatically. It is through 

these expected improvements that NREL 

has estimated reduced production costs 

for biochemical cellulosic ethanol 

plants. 

Thermochemical conversion is 

another reaction pathway which exists 

for converting cellulose to ethanol. 

Thermochemical technology is based on 

the heat and pressure-based gasification 

or pyrolysis of nearly any biomass 

feedstock, including those we’ve 

highlighted as likely biochemical 

feedstocks. The syngas is converted into 

mixed alcohols, hydrocarbon fuels, 

chemicals, and power. A 

thermochemical unit can also 

complement a biochemical processing 

plant to enhance the economics of an 

integrated biorefinery by converting 

lignin-rich, non-fermentable material 

left over from high-starch or cellulosic. 

NREL has not yet estimated the cost of 

thermochemically converting cellulose 

to ethanol, so we did not include a cost 

estimate using this potential conversion 

pathway in our analysis and based our 

cost analysis entirely on the 

biochemical route.452 However, one 

25078 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

thus it could not be relied upon for any part of our 

real-world program cost analysis. 

453 International Energy Agency (IEA), ‘‘Biofuels 

for Transport: An International Perspective,’’ 2004. 

454 Goldemberg, J. as sited in Rothkopf, Garten, 

‘‘A Blueprint for Green Energy in the Americas,’’ 

2006. 

455Unicamp ‘‘A Expansa ̄o do Proalcool como 

Programa de Desenvolvimento Nacional’’. 

Powerpoint presentation at Ethanol Seminar in 

BNDES, 2006. As sited in OECD, ‘‘Biofuels: Linking 

Support to Performance,’’ ITF Round Tables No. 

138, March 2008. 

456 Ibid. 

457 Ibid. 

458 Ibid. 

report estimated that the costs are 

similar for converting cellulose to 

ethanol either through either the 

biochemical or thermochemical routes. 

Thus, we believe that our cellulosic 

ethanol costs are representative of both 

technologies. In Section VIII.A.3 below, 

we discuss the costs for a 

thermochemical route for producing 

diesel fuel, often referred to as biomassto-liquids (BTL) process. 

c. Imported Sugarcane Ethanol 

We based our imported ethanol fuel 

costs on cost estimates of sugarcane 

ethanol in Brazil. Generally, ethanol 

from sugarcane produced in developing 

countries with warm climates is much 

cheaper to produce than ethanol from 

grain or sugar beets. This is due to 

favorable growing conditions, relatively 

low cost feedstock and energy inputs, 

and other cost reductions gained from 

years of experience. 

As discussed in Chapter 4 of the 

DRIA, our literature search of 

production costs for sugar cane ethanol 

in Brazil indicates that production costs 

tend to range from as low as $0.57 per 

gallon of ethanol to as high as $1.48 per 

gallon of ethanol. This large range for 

estimating production costs is partly 

due to the significant variations over 

time in exchange rates, costs of 

sugarcane and oil products, etc. For 

example, earlier estimates may 

underestimate current crude and natural 

gas costs which influence the cost of 

feedstock as well as energy costs at the 

plant. Another possible difference in 

production cost estimates is whether or 

not the estimates are referring to 

hydrous or anhydrous ethanol. Costs for 

anhydrous ethanol (for blending with 

gasoline) are typically several cents per 

gallon higher than hydrous ethanol (for 

use in dedicated ethanol vehicles in 

Brazil).453 It is not entirely clear from 

the majority of studies whether reported 

costs are for hydrous or anhydrous 

ethanol. Yet another difference could be 

the slate of products the plant is 

producing, for example, future plants 

may be dedicated ethanol facilities 

while others involve the production of 

both sugar and ethanol in the same 

facility. Due to economies of scale, 

production costs are also typically 

smaller per gallon for larger facilities. 

The study by OECD (2008) entitled 

‘‘Biofuels: Linking Support to 

Performance’’, appears to provide the 

most recent and detailed set of 

assumptions and production costs. As 

such, our estimate of sugarcane 

production costs primarily relies on the 

assumptions made for the study, which 

are shown in Table VIII.A.1–4. The 

estimate assumes an ethanol-dedicated 

mill and is based off an internal rate of 

return of 12%, a debt/equity ratio of 

50% with an 8% interest rate and a 

selling of surplus power at $57 per 

MWh. 

TABLE VIII.A.1–4—COST OF PRODUCTION IN A STANDARD ETHANOL PROJECT IN BRAZIL

Sugarcane Productivity ............................................................................................................................ 71.5 t/ha. 

Sugarcane Consumption .......................................................................................................................... 2 million tons/year. 

Harvesting days ....................................................................................................................................... 167. 

Ethanol productivity .................................................................................................................................. 85 liters/ton (22.5 gal/ton). 

Ethanol production ................................................................................................................................... 170 million liters/year (45 MGY). 

Surplus power produced .......................................................................................................................... 40 kWh/ton sugarcane. 

Investment cost in mill ............................................................................................................................. USD 97 million. 

Investment cost for sugarcane production ............................................................................................... USD 36 million. 

O & M (Operating & Maintenance) costs ................................................................................................. $0.26/gal. 

Sugarcane costs ...................................................................................................................................... $0.64/gal. 

Capital costs ............................................................................................................................................. $0.49/gal. 

Total production costs ....................................................................................................................... $1.40/gal. 

The estimate above is based on the 

costs of producing ethanol in Brazil on 

average, today. However, we are 

interested in how the costs of producing 

ethanol will change by the year 2022. 

Although various cost estimates exist, 

analysis of the cost trends over time 

shows that the cost of producing ethanol 

in Brazil has been steadily declining 

due to efficiency improvements in cane 

production and ethanol conversion 

processes. Between 1980 and 1998 (total 

span of 19 years) ethanol cost declined 

by approximately 30.8%.454 This change 

in the cost of production over time in 

Brazil is known as the ethanol cost 

‘‘Learning Curve’’. 

The change in ethanol costs will 

depend on the likely productivity gains 

and technological innovations that can 

be made in the future. As the majority 

of learning may have already occurred, 

it is likely that the decline in sugarcane 

ethanol costs will be less drastic as the 

production process and cane practices 

have matured. This is in contrast to 

younger technologies such as those used 

to produce cellulosic biofuels which 

could likely have larger cost reductions 

over the same period of time. In fact, 

there are few perspectives for 

substantial efficiency gains with the 

sugarcane processing technology. 

Industrial efficiency gains are already at 

about 85% and are expected to increase 

to 90% in 2015.455 Most of the 

productivity growth is expected to come 

from sugarcane production, where 

yields are expected to grow from the 

current 70 tons/ha, to 96 tons/ha in 

2025.456 Sugarcane quality is also 

expected to improve, with sucrose 

content growing from 14.5% to 17.3% 

in 2025.457 All productivity gains 

together could allow the increase in the 

production of ethanol from 6,000 liters/ 

ha (at 85 liters/ton sugarcane in 2005) to 

10,400 liters/ha (at 109 liters/ton 

sugarcane) by 2025.458 Although not 

reflected here, there could also be cost 

and efficiency improvements related to 

feedstock collection, storage, and 

distribution. 

Assuming that ethanol productivity 

increases to 100 liters/ton by 2015 and 

109 liters/ton by 2025, sugarcane costs 

are be expected to decrease to 

approximately $0.51/gal from $0.64/gal 

since less feedstock is needed to 

produce the same volume of ethanol 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25079 

459Macedo. I.C., ‘‘Green house gases emissions in 

the production and use of ethanol from sugarcane 

in Brazil: The 2005/2006 Averages and a Prediction 

for 2020,’’ Biomass and Bioenergy, 2008. 

460Smeets E, Junginger M, Faaij A, Walter A, 

Dolzan P, Turkenburg W, ‘‘The sustainability of 

Brazilian ethanol—An Assessment of the 

possibilities of certified production,’’ Biomass and 

Bioenergy, 2008. 

461Official Statistics of the U.S. Department of 

Commerce, USITC. 

using the estimates from Table VIII.A.1– 

4, above. We assumed a linear decrease 

between data points for 2005, 2015, and 

2025. Adding operating ($0.26/gal) and 

capital costs ($0.49/gal) from Table 

VIII.A.1–4, to a sugarcane cost of $0.51/ 

gal, total production costs are $1.26/gal 

in 2022. 

Brazil sugarcane producers are also 

expected to move from burned cane 

manual harvesting to mechanical 

harvesting. As a result, large amounts of 

straw are expected to be available. Costs 

of mechanical harvesting are lower 

compared to manually harvesting, 

therefore, we would expect costs for 

sugarcane to decline as greater 

sugarcane producers move to 

mechanical harvesting. However, it is 

important to note that diesel use 

increases with mechanical harvesting, 

and with diesel fuel prices expected to 

increase in the future, costs may be 

higher than expected. Therefore, we 

have not assumed any changes to 

harvesting costs due to the switchover 

from manual harvesting to mechanical 

harvesting. 

As more straw is expected to be 

collected at future sugarcane ethanol 

facilities, there is greater potential for 

production of excess electricity. The 

production costs estimates in the OECD 

study assumes an excess of 40kWh per 

ton sugarcane, however, future 

sugarcane plants are expected to 

produce 135 kWh per ton sugarcane.459

Assuming excess electricity is sold for 

$57 per MWh, the production of 95 kWh 

per ton would be equivalent to a credit 

of $0.22 per gallon ethanol produced. 

We did not include this potential 

additional credit from greater use of 

bagasse and straw in our estimates at 

this time. Our cost estimates do include, 

however, the excess electricity 

produced from bagasse that is currently 

used today (40 kWh/ton). We are asking 

for comment on whether such a credit 

should be included in our production 

cost estimates. 

It is also important to note that 

ethanol production costs can increase if 

the costs of compliance with various 

sustainability criteria are taken into 

account. For instance, using organic or 

green cane production, adopting higher 

wages, etc. could increase production 

costs for sugarcane ethanol.460 Such 

sustainability criteria could also be 

applicable to other feedstocks, for 

example, those used in corn- or soybased biofuel production. If these 

measures are adopted in the future, 

production costs will be higher than we 

have projected. 

In addition to production costs, there 

are also logistical and port costs. We 

used the report from AgraFNP to 

estimate such costs since it was the only 

resource that included both logistical 

and port costs. The total average 

logistical and port cost for sugarcane 

ethanol is $0.19/gal and $0.09/gal, 

respectively, as shown in Table 

VIII.A.1–5. 

TABLE VIII.A.1–5—IMPORTED ETHANOL COST AT PORT IN BRAZIL (2006 $) 

Region 

Logistical 

costs U.S. 

($/gal) 

Port cost U.S. 

($/gal) 

NE Sao Paulo .......................................................................................................................................................... 0.146 0.094 

W Sao Paulo ............................................................................................................................................................ 0.204 0.094 

SE Sao Paulo .......................................................................................................................................................... 0.100 0.094 

S Sao Paulo ............................................................................................................................................................. 0.170 0.094 

N Parana .................................................................................................................................................................. 0.232 0.094 

S Goias .................................................................................................................................................................... 0.328 0.094 

E Mato Grosso do sul .............................................................................................................................................. 0.322 0.094 

Triangulo mineiro ..................................................................................................................................................... 0.201 0.094 

NE Cost ................................................................................................................................................................... 0.026 0.058 

Sao Francisco Valley ............................................................................................................................................... 0.188 0.058 

Average ............................................................................................................................................................ 0.192 0.087 

Total fuel costs must also include the 

cost to ship ethanol from Brazil to the 

U.S. In 2006, this cost was estimated to 

be approximately $0.15 per gallon of 

ethanol.461 Costs were estimated as the 

difference between the unit value cost of 

insurance and freight (CIF) and the unit 

value customs price. The average cost to 

ship ethanol from Caribbean countries 

(e.g., El Salvador, Jamaica, etc.) to the 

U.S. in 2006 was approximately $0.12 

per gallon of ethanol. Although this may 

seem to be an advantage for Caribbean 

countries, it should be noted that there 

would be some additional cost for 

shipping ethanol from Brazil to the 

Caribbean country. Therefore, we 

assume all costs for shipping ethanol to 

be $0.15 per gallon regardless of the 

country importing ethanol to the U.S. 

Total imported ethanol fuel costs (at 

U.S. ports) prior to tariff and tax for 

2022 is shown in Table VIII.A.1–6, at 

$1.69/gallon. Direct Brazilian imports 

are also subject to an additional $0.54 

per gallon tariff, whereas those imports 

arriving in the U.S. from Caribbean 

Basin Initiative (CBI) countries are 

exempt from the tariff. In addition, all 

imports are given an ad valorem tax of 

2.5% for undenatured ethanol and a 

1.9% tax for denatured ethanol. We 

assumed an ad valorem tax of 2.5% for 

all ethanol. Thus, including tariffs and 

ad valorem taxes, the average cost of 

imported ethanol is shown in Table 

VIII.A.1–7 in the ‘‘Brazil Direct w/Tax & 

Tariff’’ and ‘‘CBI w/Tax’’ columns for 

2022. 

25080 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

462Haas, M.J., A process model to estimate 

biodiesel production costs, Bioresource Technology 

97 (2006) 671–678. 

TABLE VIII.A.1–6—AVERAGE IMPORTED ETHANOL COSTS PRIOR TO TARIFF AND TAXES IN 2022 

Sugarcane production cost 

($/gal) 

Operating cost 

($/gal) 

Capital cost 

($/gal) 

Logistical cost 

($/gal) 

Port cost 

($/gal) 

Transport cost 

from port to 

U.S. 

($/gal) 

Total cost 

($/gal) 

0.51 .......................................................... 0.26 0.49 0.19 0.09 0.15 1.69 

TABLE VIII.A.1–7—AVERAGE IMPORTED ETHANOL COSTS IN 2022 

Brazil direct ($/gal) Brazil direct w/tax & tariff 

($/gal) CBI ($/gal) CBI w/tax ($/gal) 

1.69 ................................................................ 2.27 1.69 1.73 

2. Biodiesel and Renewable Diesel 

Production Costs 

Biodiesel and renewable diesel 

production costs are primarily a 

function of the feedstock cost, and to a 

much lesser extent, the capital and other 

operating costs of the facility. 

a. Biodiesel 

Biodiesel production costs for this 

rule were estimated using two versions 

of a biodiesel production facility model 

obtained from USDA, one using 

degummed soy oil as a feedstock and 

the other using yellow grease. The 

biodiesel from yellow grease model 

includes the acid pre-treatment steps 

required to utilize feedstocks with high 

free fatty acid content. 

This production model simulates a 10 

million gallon per year plant operating 

a continuous flow transesterification 

process. USDA used the SuperPro 

Designer chemical process simulation 

software to estimate heat and material 

flowrates and equipment sizing. 

Outputs from this software were then 

combined in a spreadsheet with 

equipment, energy, labor, and chemical 

costs to generate a final estimate of 

production cost. The model is described 

in a 2006 publication in Bioresource 

Technology, peer-reviewed scientific 

journal.462 Table VIII.A.2–1 shows the 

production cost allocation for the soy 

oil-to-biodiesel facility as modeled in 

the 2022 policy case. 

TABLE VIII.A.2–1—PRODUCTION COST

ALLOCATION FOR SOY BIODIESEL

DERIVED FROM THIS ANALYSIS

Cost category 

Contribution to 

cost 

(percent) 

Soy Oil ......................................... 87 

Other Materials a ......................... 5 

TABLE VIII.A.2–1—PRODUCTION COST

ALLOCATION FOR SOY BIODIESEL

DERIVED FROM THIS ANALYSIS— 

Continued 

Cost category 

Contribution to 

cost 

(percent) 

Capital & Facility ......................... 4 

Labor ........................................... 3 

Utilities ......................................... 1 

a Includes acids, bases, methanol, catalyst. 

Soy oil costs were generated by the 

FASOM agricultural model (described 

in more detail in Section IX.A). 

Historically, the majority of biodiesel 

production in the U.S. has used soy oil, 

a relatively high-value feedstock, but a 

growing fraction of biodiesel is being 

made from yellow grease, the name 

given to reclaimed or highly-processed 

oil (including corn oil extracted from 

distillers’ grains) that is not suitable for 

use in food products. This material 

typically sells for about 70% of the 

value of virgin soy oil. Conversion of 

yellow grease into biodiesel requires an 

additional acid pretreatment step, and 

therefore the processing costs are higher 

than for virgin soy oil (about $0.40/gal 

at equal feedstock costs). Table VIII.A.2– 

2 shows the feedstock and biodiesel 

costs used in our cost analysis. 

TABLE VIII.A.2–2—BIODIESEL FEEDSTOCK AND PRODUCTION COSTS

USED IN THIS ANALYSIS (2006$) 

Soy oil Yellow 

grease a

Reference 

Case ...... ........................ ........................

Feedstock 

$/lb $0.23 $0.16 

Biodiesel 

$/gal $2.11 $1.99 

Policy Case ........................ ........................

TABLE VIII.A.2–2—BIODIESEL FEEDSTOCK AND PRODUCTION COSTS

USED IN THIS ANALYSIS (2006$)— 

Continued 

Soy oil Yellow 

grease a

Feedstock 

$/lb $0.32 $0.22 

Biodiesel 

$/gal $2.75 $2.47 

a Includes corn oil extracted from thin 

stillage/DGS, rendered fats, recycled greases, 

etc. 

A co-product of transesterification is 

crude glycerin. With the upswing in 

worldwide biodiesel production in 

recent years, its market price is 

relatively low: In our modeling we 

assume its value to be $0.03/lb. As a 

result, the sale of this material as a coproduct only reduces biodiesel 

production cost by about $0.02/gal. 

b. Renewable Diesel 

Renewable diesel is produced in one 

of three general configurations: (1) A 

new standalone unit located within a 

refinery, (2) co-processing in an existing 

refinery diesel hydrotreater, or (3) a 

standalone unit at a rendering plant or 

another location outside of a refinery. 

We expect that the largest fraction of the 

capacity for refinery installation will be 

produced using the co-processing 

method, as the production costs are 

lower than those for a new standalone 

unit in a refinery. Thus, we speculate 

that about 50% of renewable diesel 

being produced by the refinery coprocessing route, 17% from a new stand 

alone unit at a refinery and 33% at 

rendering plants or as a new site 

installation. Recent business 

partnership and construction 

announcements related to renewable 

diesel production (such as involving 

ConocoPhillips facilities in Texas, and 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25081 

463A New Development in Renewable Fuels: 

Green Diesel, AM–07–10 Annual Meeting NPRA, 

March 18–20, 2007. 

464From Securities and Exchange Commission 

Form 8–K for Syntroleum Corp, June 25th 07. 

Tyson-Syntroleum facilities in 

Louisiana) generally support such a 

split. 

We derived our production cost 

estimates from documents made 

available publicly by UOP, Inc., to make 

renewable diesel in a grass roots 

standalone production process inside a 

refinery.463 The process has a pretreating unit that removes alkali and 

acidic producing compounds from feed 

streams, which removes the catalyst 

poisons. We also used the UOP 

engineering estimate to derive costs for 

co-processing renewable diesel in an 

existing refinery’s diesel hydrotreater. 

For this, we assumed that refiners will: 

(1) revamp their existing diesel 

hydrotreater to add capacity and (2) add 

a pre-treater to remove feedstock 

contaminants. Lastly, we derived costs 

for a standalone unit at a location 

outside a refinery at a rendering plant 

other facility, using a capital cost 

estimate from Syntroleum Corp.464

The extent of the depolymerization 

and hydrotreating reactions depend on 

the process conditions, as some of the 

carbon backbone of the oils can be 

cracked to naphtha and lighter products 

with higher severity. For our analysis, 

we assume no such cracking and predict 

yields resulting in ninety-nine percent 

diesel fuel with the balance as propane 

(which could also be considered 

renewable fuel) and water. We assume 

that all of the renewable diesel 

production will take place in PADD 2, 

as feedstock shipping costs are reduced 

since most of the sources for feedstock 

supply are located primarily in the 

Midwest. Average processing cost per 

gallon (in addition to the feedstock) is 

41 cents for making renewable diesel 

from yellow grease/animal fats, based 

on our cost methodology. 

As with biodiesel, renewable diesel 

cost estimates were based on soy oil 

feedstock prices taken from the FASOM 

modeling work, given in Section IX.A. 

Our cost estimates for renewable diesel 

were focused on use of yellow grease as 

a feedstock, given the project 

announcements mentioned above, as 

well as the relative insensitivity of the 

hydrotreating process to fatty acids and 

other contaminates relative to the 

transesterification process. Oil from 

corn fractionation, yellow grease, and 

animal fat prices were assumed to be 

70% the price of soy oil (consistent with 

historical market trends). For our 2022 

policy case, with a yellow grease price 

of $0.23/lb, the production cost is $2.47/ 

gal for biodiesel and $2.10/gal for 

renewable diesel (2006$). Table 

VIII.A.2–3 shows the projected volume 

contribution to the biodiesel and 

renewable diesel total volume, their 

production costs, and the weighted 

average production cost used for 

biodiesel and renewable diesel in this 

proposal. These results assume 

feedstock prices are plant-gate and do 

not include any product transportation 

costs. Note also that the volumes here 

include co-processed renewable diesel 

which does not qualify as biomassbased diesel but which may be counted 

as advanced biofuel. 

TABLE VIII.A.2–3—PROJECTED COSTS AND VOLUME CONTRIBUTION FOR BIODIESEL AND RENEWABLE DIESEL

[Policy case, 2006$ and million gallons] 

Fuel Cost Volume 

Biodiesel from virgin plant oil .................................................................................................................................. 2.75 660 

Biodiesel from oil extraction at ethanol plants, yellow grease ................................................................................ 2.47 150 

Renewable diesel from fat, oil, yellow grease ......................................................................................................... 2.10 375 

Weighted average cost & total volume ................................................................................................................... 2.51 1,185 

Although the per-gallon cost for 

making renewable diesel from yellow 

grease is significantly less than using 

the biodiesel process, there are a 

number of reasons why we believe the 

latter will still be used to process some 

yellow grease (and most of the virgin oil 

feedstocks). The primary reason is that 

there is already sufficient biodiesel 

capacity existing or under construction 

to cover the projected volumes. 

Secondly, the per-gallon capital cost to 

build new hydroprocessing capacity for 

renewable diesel is expected to be 

significantly higher than for the 

biodiesel process. The low per-gallon 

renewable diesel cost given here is 

based on the majority of the production 

being done by co-processing at existing 

petroleum refineries. 

3. BTL Diesel Production Costs 

Biofuels-to-Liquids (BTL) processes, 

which are also thermochemical 

processes, convert biomass to liquid 

fuels via a syngas route. The primary 

product produced by this process is 

diesel fuel. 

There are many steps involved in a 

BTL process which makes this a capitalintensive process. The first step, like all 

the cellulosic processes, requires that 

the feedstocks be processed to be dried 

and ground to a fine size. The second 

step is the syngas step, which 

thermochemically reacts the biomass to 

carbon monoxide and hydrogen. Since 

carbon monoxide production exceeds 

the stoichiometric ideal fraction of the 

mixture, a water shift reaction must be 

carried out to increase the relative 

balance of hydrogen. The syngas 

products must then be cleaned to 

facilitate the following Fischer-Tropsch 

reaction. The Fischer-Tropsch reaction 

reacts the syngas to a range of 

hydrocarbon compounds—a type of 

synthetic crude oil. This hydrocarbon 

mixture is then hydrocracked to 

maximize the production of high cetane 

diesel fuel, although some low octane 

naphtha is also produced. The many 

steps of the BTL process contribute to 

its high capital cost. 

One estimate made by Iowa State 

University estimates the total cost for a 

cellulosic Fischer-Tropsch plant that 

produces 35 million gallons per year 

diesel fuel at $2.37 per gallon. This cost 

estimated the capital costs to be $341 

million. These costs were estimated in 

the year 2002. We adjusted the 

operating and capital costs to a 2006 

investment environment and to 2006 

dollars based the costs on our average 

$71/dry ton feedstock costs which 

increases the total cost to $2.85 per 

gallon of diesel fuel. 

Initially, the estimated cost of $2.85 

per gallon seems high relative to the 

projected cost for a year 2015 

biochemical cellulosic plant, which is 

$1.39 per gallon of ethanol in 2006 

dollars. However, ethanol provides 

about half the energy content as FischerTropsch diesel fuel. So if we double the 

biochemical cellulosic ethanol costs to 

$2.78 per diesel fuel-equivalent gallon, 

25082 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

465The anticipated ways that the renewable fuels 

projected to be used in response to the EISA will 

be distributed is discussed in Section V.C. of 

today’s preamble. 

466Please refer to Section 4.2 of the DRIA for 

additional discussion of how these estimates were 

derived. 

467See Section V.C. of today’s preamble for 

discussion of the upgrades we project will be 

needed to the distribution system to handle the 

increase in ethanol volumes under EISA. 

468These capital costs will be incurred 

incrementally through 2022 as ethanol volumes 

increase. Capital costs for tank trucks were 

amortized over 10 years with a 7% cost of capital. 

Other capital costs were amortized over 15 years 

with a 7% return on capital. 

469 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National 

Laboratory, March 2009. 

470Please refer to Section 4.2 of the DRIA for 

additional discussion of ethanol freight costs. 

471Our projections regarding the location of 

ethanol production/import volumes and where 

ethanol would be used is discussed in Sections V.B. 

and V.D. of today’s preamble respectively. 

the estimated costs are very consistent 

between the two. The cellulosic biofuel 

tax subsidy favors the biochemical 

ethanol plant, though, because it is a 

per-gallon subsidy regardless of the 

energy content, and it therefore offsets 

twice as much cost as the BTL plant 

producing diesel fuel. There is one more 

issue worth considering and that is the 

relative price of diesel fuel to that of 

E85. Recently diesel fuel has been 

priced much higher than gasoline, and 

if this trend continues to hold, it would 

provide a better market for selling the 

BTL diesel fuel than for selling 

biochemical ethanol into the E85 

market, which we believe will be a 

challenging pricing market for refiners. 

4. Catalytic Depolymerization Costs 

A new technology was developed by 

Cello Energy which catalytically 

depolymerizes cellulose, and then 

repolymerizes it to produce synthetic 

hydrocarbon fuels such as gasoline, jet 

fuel and diesel fuel The company claims 

that they can produce diesel fuel for 

about $0.40 per gallon by processing 

hay, wood chips and used tires. Based 

on our projections of future cellulosic 

feedstock costs, their production costs 

for using only cellulosic feedstocks and 

assuming the cellulosic feedstock costs 

developed above would likely be about 

$1.00 per gallon. In late 2008 the 

company started up a 20 million gallon 

per year commercial demonstration 

plant as a first step towards 

commercializing their process. We 

discuss this technology and its costs in 

more detail in the DRIA. 

B. Distribution Costs 

Our analysis of the costs associated 

with distributing the volumes of 

renewable fuels that we project will be 

used under RFS2 focuses on: (1) The 

capital cost of making the necessary 

upgrades to the fuel distribution 

infrastructure system directly related to 

handling these fuels, and (2) the 

ongoing additional freight costs 

associated with shipping renewable 

fuels to the point where they are 

blended with petroleum-based fuels.465

The following sections outline our 

estimates of the distribution costs for 

the additional volumes of ethanol, 

FAME biodiesel, and renewable diesel 

fuel that would be used in response to 

the RFS2 standards.466

A discussion of the capability of the 

transportation system to accommodate 

the volumes of renewable fuels 

projected to be used under RFS2 is 

contained in Section V.C. of today’s 

preamble. There will be ancillary costs 

associated with upgrading the basic rail, 

marine, and road transportation nets to 

handle the increase in freight volume 

due to the RFS2. We have not sought to 

quantify these ancillary costs because 

(1) the growth in freight traffic that is 

attributable to RFS2 represents a 

minimal fraction of the total anticipated 

increase in freight tonnage 

(approximately 2% by 2022, see Section 

V.C.4.), and (2) we do not believe there 

is an adequate way to estimate such 

non-direct costs. We will continue to 

evaluate issues associated with the 

expansion of the basic transportation 

net to accommodate the volumes of 

renewable fuels projected under RFS2 

and will update our analysis for the 

final rule based on our findings. 

1. Ethanol Distribution Costs 

a. Capital Costs To Upgrade the 

Distribution System for Increased 

Ethanol Volume 

Table VIII.B.1–1 contains our 

estimates of the infrastructure changes 

and associated capital costs to support 

the use of the additional 21 BGY of 

ethanol that we project will be used 

under RFS2 by 2022 relative to the AEO 

2007 forecast of 13 BGY.467 The total 

estimated capital costs are estimated at 

$12.1 billion which when amortized 

equates to approximately 6.9 cents per 

gallon of this additional ethanol 

volume.468

TABLE VIII.B.1–1—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS A

Million $ 

Fixed Facilities: 

Marine Import Facilities ............ 49 

Ethanol Receipt Rail Hub Terminals: 

Rail Car Handling & Misc. 

Equipment ......................... 1,264 

Ethanol Storage Tanks ......... 354 

Petroleum Terminals: 

Rail Receipt Facilities ........... 2,482 

Ethanol Storage Tanks ......... 1,611 

TABLE VIII.B.1–1—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS A—Continued 

Million $ 

Ethanol Blending & Misc. 

Equipment ......................... 545 

Retail ......................................... 2,957 

Mobile Facilities: 

Rail Cars ................................... 2,938 

Barges ...................................... 183 

Tank Trucks .............................. 223 

Total Capital Costs ............... 12,066 

a Relative to a 13.18 BGY 2022 reference 

case. 

We request comment on our basis for 

these estimates as detailed in chapter 

4.2 of the DRIA. Comment is specifically 

requested on the extent to which 

ethanol rail receipt would be 

accommodated within petroleum 

terminals rather than being cited at rail 

hub terminals (to be further shipped by 

tank truck to petroleum terminals). Our 

current analysis estimated that half of 

the new ethanol rail receipt capability 

needed to support the use of the 

projected ethanol volumes under the 

EISA would be installed at petroleum 

terminals, and half would be installed at 

rail terminals. A recently completed 

study by ORNL estimated that all new 

ethanol rail receipt capability would be 

installed at existing rail terminals given 

the limited ability to install such 

capability at petroleum terminals.469

b. Ethanol Freight Costs 

We estimate that ethanol freight costs 

would be 11.3 cents per gallon on a 

national average basis. Ethanol freight 

costs are based on those we derived for 

the Renewable Fuel Standard final rule 

updated to reflect the projected ethanol 

use patterns and effect on distribution 

patterns of increased imports and more 

dispersed domestic ethanol production 

locations.470 Specifically, we estimated 

freight costs by assessing the location of 

production and import volumes, where 

ethanol would be used, and the modes 

and distances for transportation 

between production and use.471 We 

intend to update our estimate of ethanol 

freight costs for the final rule based on 

a recently completed analysis 

conducted for EPA by Oak Ridge 

National Laboratory (ORNL). The ORNL 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25083 

472We project that by 2022 380 MGY of FAME 

biodiesel would be used absent the requirements 

under EISA and that a total of 810 MGY of FAME 

biodiesel would be used under the EISA. 

473These capital costs will be incurred 

incrementally through 2022 as FAME biodiesel 

volumes increase. Capital costs for tank trucks were 

amortized over 10 years with a 7% cost of capital. 

Other capital costs were amortized over 15 years 

with a 7% return on capital. 

474This includes co-processed renewable diesel 

fuel as well as renewable diesel fuel produced in 

separate processing units located at refineries. 

analysis contains more detailed 

projections of which transportation 

modes and combination of modes (e.g., 

unit train to barge) are best suited for 

delivery of ethanol to specific markets 

considering ethanol source and end use 

locations, the current configuration and 

projected evolution of the distribution 

system, and cost considerations for the 

different transportation modes. 

2. Biodiesel and Renewable Diesel 

Distribution Costs 

a. Capital Costs To Upgrade the 

Distribution System for Increased FAME 

Biodiesel Volume 

Table VIII.B.2–1 contains our 

estimates of the infrastructure changes 

and associated capital costs to support 

the use of the additional 430 MGY of 

FAME biodiesel that we project will be 

used under RFS2 by 2022.472 The total 

capital costs are estimated at $381 

million which equates to approximately 

9.8 cents per gallon of additional 

biodiesel volume.473

TABLE VIII.B.2–1—ESTIMATED FAME 

BIODIESEL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS a

Million $ 

Fixed Facilities: 

Petroleum Terminals: 

Storage Tanks ....................... 129 

Biodiesel Blending & Misc. 

Equipment ......................... 192 

Mobile Facilities: 

Rail Cars ................................... 35 

Barges ...................................... 17 

Tank Trucks .............................. 8 

Total Capital Costs ............... 381 

a Relative to a 380 MGY 2022 reference 

case. 

b. Biodiesel Freight Costs 

We estimate that biodiesel freight 

costs would be 9.3 cents per gallons on 

a national average basis. Priority 

regional demand for biodiesel was 

estimated by reviewing State biodiesel 

mandates/incentives and assuming a 

demand for 2% biodiesel in most 

heating oil used in the Northeast by 

2022. This priority regional demand was 

assumed to be filled first from local 

plants that could ship economically by 

tank truck. The remaining fraction of 

priority regional demand was assumed 

to be satisfied from more distant plants 

via shipment by manifest rail car. 

Overall shipping distances were 

minimized in selecting which plants 

would satisfy the demand for a given 

area. The amount of biodiesel that we 

project would be consumed which 

would not be directed to priority 

demand was assumed to be used within 

trucking distance of the production 

plant to the extent possible while 

maintaining biodiesel blend 

concentrations below 5%. The 

remaining volume needed to match our 

estimated production volume was 

assumed to be shipped via manifest rail 

car to the nearest areas where diesel fuel 

use was not already saturated with 

biodiesel to the 5% level. 

c. Renewable Diesel Distribution System 

Capital and Freight Costs 

We project that there would be no 

additional costs associated with 

distributing the 250 MGY of renewable 

diesel fuel that we estimate will be 

produced at refineries by 2022.474 This 

renewable diesel fuel will be blended 

into finished diesel fuel at the refinery 

and be distributed to petroleum 

terminals in the same way 100% 

petroleum-based distillate fuel is 

distributed. This is based on our belief 

that renewable diesel will be confirmed 

to be sufficiently similar to petroleumbased diesel with respect to distribution 

system compatibility. 

We project that 125 MGY of 

renewable diesel will be produced at 

stand-alone facilities that are not 

connected to a refinery or petroleum 

terminal. We estimate that such 

renewable diesel will be trucked to 

nearby petroleum terminals at a cost of 

5 cents per gallon. We estimate that 8 

additional tank trucks would be needed 

to carry this renewable diesel to 

terminals at a total cost of 

approximately $1.3 million dollars. 

Amortized over 10 years with a 7% cost 

of capital, the total capital costs equate 

to approximately 0.2 cents per gallon of 

renewable diesel fuel produced at standalone facilities. We estimate that no 

further capital costs would need to be 

incurred to handle renewable diesel 

fuel. This is based on the assumption 

that renewable diesel delivered to 

terminals from stand-alone production 

facilities can be mixed directly into 

storage tanks that contain petroleumbased diesel fuel or can be stored 

separately in existing storage tanks for 

later blending with petroleum-based 

diesel fuel. We further estimate the 

terminals that receive renewable diesel 

will not need to install additional 

facilities to allow the receipt by tank 

truck. 

C. Reduced Refining Industry Costs 

As renewable and alternative fuel use 

increases, the volume of petroleumbased products, such as gasoline and 

diesel fuel, would decrease. This 

reduction in finished refinery petroleum 

products is associated with reduced 

refinery industry costs. The reduced 

costs would essentially be the volume of 

fuel displaced multiplied by the cost for 

producing the fuel. There is also a 

reduction in capital costs which is 

important because by not investing in 

new refinery capital, more resources are 

freed up to build plants that produce 

renewable and alternative fuels. 

Although we conducted refinery 

modeling for estimating the cost of 

blending ethanol, we did not rely on the 

refinery model results for estimating the 

volume of displaced petroleum. Instead 

we conducted an energy balance around 

the increased use of renewable fuels, 

estimating the energy-equivalent 

volume of gasoline or diesel fuel 

displaced. This allowed us to more 

easily apply our best estimates for how 

much of the petroleum would displace 

imports of finished products versus 

crude oil for our energy security 

analysis which is discussed in Section 

IX.B of this preamble. 

As part of this analysis we accounted 

for the change in petroleum demanded 

by upstream processes related to 

additional production of the renewable 

fuels as well as reduced production of 

petroleum fuels. For example, growing 

corn used for ethanol production 

requires the use of diesel fuel in 

tractors, which reduces the volume of 

petroleum displaced by the ethanol. 

Similarly, the refining of crude oil uses 

by-product hydrocarbons for heating 

within the refinery, therefore the overall 

effect of reduced gasoline and diesel 

fuel consumption is actually greater 

because of the additional upstream 

effect. We used the lifecycle petroleum 

demand estimates provided for in 

GREET model to account for the 

upstream consumption of petroleum for 

each of the renewable and alternative 

fuels, as well as for gasoline and diesel 

fuel. Although there may be some 

renewable fuel used for upstream 

energy, we assumed that this entire 

volume is petroleum because the 

volume of renewable and alternative 

fuels is fixed as described in Section V 

above. 

For this proposed rule, we assumed 

that a portion of the gasoline displaced 

25084 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

by ethanol is imported, while the other 

portion is produced from domestic 

refineries. The assumption we made is 

that one half of the ethanol market in 

the Northeast, which comprises about 

half of the nation’s gasoline demand, 

would displace imported gasoline or 

gasoline blend stocks. Therefore, to 

derive the portion of the new renewable 

fuels which would offset imports (and 

not impact domestic refinery 

production), we multiplied the total 

volume of petroleum fuel displaced by 

50% to represent that portion of the 

ethanol which would be used in the 

Northeast, and 50% again to only 

account for that which would offset 

imports. The rest of the ethanol, 

including half of the ethanol presumed 

to be used in the Northeast, is presumed 

to offset domestic gasoline production. 

In the case of biodiesel and renewable 

diesel, all of it is presumed to offset 

domestic diesel fuel production. For 

ethanol, biodiesel and renewable diesel, 

the amount of petroleum fuel displaced 

is estimated based on the relative energy 

contents of the renewable fuels to the 

fuels which they are displacing. The 

savings due to lower imported gasoline 

and diesel fuel is accounted for in the 

energy security analysis contained in 

Section IX.B. 

For estimating the U.S. refinery 

industry cost reductions, we multiplied 

the estimated volume of domestic 

gasoline and diesel fuel displaced by the 

wholesale price for each of these fuels, 

which are $157 per gallon for gasoline, 

and $161 per gallon for diesel fuel at 

$53/bbl crude oil, and $267 per gallon 

for gasoline, and $335 per gallon for 

diesel fuel at $92/bbl crude oil. For the 

volume of petroleum displaced 

upstream, we valued it using the 

wholesale diesel fuel price. Table 

VIII.C.1–1 shows the net volumetric 

impact on the petroleum portion of 

gasoline and diesel fuel demand, as well 

as the reduced refining industry costs 

for 2022. 

TABLE VIII.C.1–1—REDUCED U.S. REFINERY INDUSTRY COSTS FOR THE RFS2 PROGRAM IN 2022 

Total volume 

displaced 

(billion gallons) 

Cost savings at 

$53/bbl crude oil 

price 

(billion dollars) 

Cost savings at 

$92/bbl crude oil 

price 

(billion dollars) 

Upstream ................................................ Petroleum .............................................. 0.8 ¥$1.3 ¥$2.7 

End Use ................................................. Gasoline ................................................ 10.4 16.3 27.7 

Diesel Fuel ............................................ 0.6 0.9 1.9 

Total ............................................... .............................. 15.9 26.9 

D. Total Estimated Cost Impacts 

The previous sections of this chapter 

presented estimates of the cost of 

producing and distributing corn-based 

and cellulosic-based ethanol, imported 

ethanol, biodiesel, and renewable 

diesel. In this section, we briefly 

summarize the methodology used and 

the results of our analysis to estimate 

the cost and other implications for 

increased use of renewable fuels to 

displace gasoline and diesel fuel. An 

important aspect of this analysis is 

refinery modeling which primarily was 

used to estimate the costs of blending 

ethanol into gasoline, as well as the 

overall refinery industry impacts of the 

proposed fuel program. The refinery 

modeling was conducted by Jacobs 

Consultancy under subcontract to 

Southwest Research Institute. A detailed 

discussion of how the renewable fuel 

volumes affect refinery gasoline 

production volumes and cost is 

contained in Chapter 4 of the DRIA. 

1. Refinery Modeling Methodology 

The refinery modeling was conducted 

in three distinct steps. The first step 

involved the establishment of a 2004 

base case which calibrated the refinery 

model against 2004 volumes, gasoline 

quality, and refinery capital in place. 

The EPA and ASTM fuel quality 

constraints in effect by 2004 are 

imposed on the products. 

For the second step, we established a 

2022 future year reference case which 

represents a business-as-usual case as 

estimated by the 2007Annual Energy 

Outlook (AEO). The refinery model 

assumed that the price of crude oil 

would average about $51 per barrel, 

though the results were later adjusted to 

reflect $53 and $92 per barrel crude oil 

prices. We also modeled the 

implementation of several new 

environmental programs that will have 

required changes in fuel quality by 

2022, including the 30 part per million 

(ppm) average gasoline sulfur standard, 

the 15 ppm cap standards on highway 

and nonroad diesel fuel, the Mobile 

Source Air Toxics (MSAT) 0.62 volume 

percent benzene standard. We modeled 

the implementation of EPAct of 2005, 

which by rescinding the reformulated 

gasoline oxygenate standard, resulted in 

the discontinued use of MTBE, and a 

large increase in the amount of ethanol 

blended into reformulated gasoline. We 

also modeled the EISA Energy Bill 

corporate average fuel economy (cafe ́) 

standards in the reference case because 

it will be phasing-in, and affect the 

phase-in of the RFS2. We modeled 13.2 

billion gallons of ethanol in the gasoline 

pool and 0.4 billion gallons of biodiesel 

in the diesel pool for 2022, which is the 

‘‘business-as-usual’’ volume as projected 

by AEO 2007. 

The third step, or the control case, 

involved the modeling of the 34 billion 

gallons of ethanol and 1 billion gallons 

of biodiesel and renewable diesel in 

2022 to comply with EISA when the 

proposed renewable fuels program is 

fully phased-in. All the other 

environmental and ASTM fuel quality 

constraints are assumed to apply to the 

control case as well to solely model the 

impact of the RFS2 standards. 

The price of ethanol and E85 used in 

the refinery modeling is a critical 

determinant of the overall economics of 

using ethanol. Ethanol was priced 

initially based on the historical average 

price spread between regular grade 

conventional gasoline and ethanol, but 

then adjusted post-modeling to reflect 

the projected production cost for both 

corn and cellulosic-based ethanol. The 

refinery modeling assumed that all 

ethanol added to gasoline for E10 is 

match-blended for octane by refiners in 

the reference and control cases, 

although splash blending of ethanol was 

assumed to be appropriate for the 

conventional gasoline for the base case 

based on EPA gasoline data. For the 

control case, E85 was assumed to be 

priced much lower than gasoline to 

reflect its lower energy content, longer 

refueling time and lower availability 

(see Chapter 4 of the DRIA for a detailed 

discussion for how we projected E85 

prices). E85 is assumed to be blended 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25085 

475EPA typically assesses social benefits and 

costs of a rulemaking. However, this analysis is 

more limited in its scope by examining the average 

cost of production of ethanol and gasoline without 

accounting for the effects of farm subsidies that 

tend to distort the market price of agricultural 

commodities. 

with gasoline blendstock designed for 

blending with E10, and a small amount 

of butane to bring the RVP of E85 up to 

that of gasoline. Thus, unlike current 

practices today where E85 is blended at 

85% in the summer and E70 in the 

winter, we assumed that E85 is blended 

at 85% year-round. E85 use in any one 

market is limited to levels which we 

estimated would reflect the ability of 

FFV vehicles in the area to consume the 

E85 volume. 

The refinery model was provided 

some flexibility and also was 

constrained with respect to the 

applicable gasoline volatility standards 

for blending up E10. The refinery model 

allowed conventional gasoline and most 

low RVP control programs to increase 

by 1.0 pounds per square inch (psi) in 

Reid Vapor Pressure (RVP) waiver 

during the summer. However, 

wintertime conventional gasoline was 

assumed to comply with the wintertime 

ASTM RVP and Volume/Liquid (V/L) 

standards. 

The costs for producing, distributing 

and using biodiesel and renewable 

diesel are accounted for outside the 

refinery modeling. Their production and 

distribution costs are estimated first, 

compared to the costs of producing 

diesel fuel, and then are added to the 

costs estimated by the refinery cost 

model for blending the ethanol. 

The costs were adjusted to reflect the 

crude oil prices estimated by EIA in its 

Annual Energy Outlook (AEO). The 

AEO 2008 reference case projects that 

crude oil will be $53 per barrel in 2022, 

so we adjusted our costs slightly to 

reflect that slightly higher crude oil 

price. We also evaluated a higher crude 

oil price case. The high crude oil case 

price modeled for the AEO projects that 

crude oil will be $92 per barrel in 2022, 

so we adjusted our cost model to also 

estimate the program costs based on this 

higher crude oil cost. We estimated the 

program costs based on these different 

crude oil prices by adjusting the 

gasoline and diesel fuel prices to reflect 

the cost of crude oil. The crude oil costs 

also have a secondary impact on the 

production costs of various renewable 

and alternative fuels (e.g., petroleum 

used to grow corn which also has been 

reflected in our cost analysis). 

2. Overall Impact on Fuel Cost 

Based on the refinery modeling 

conducted for today’s proposed rule, we 

calculated the costs for consuming the 

additional 22 billion gallons of 

renewable fuels in 2022 relative to the 

reference case. The costs are reported 

separately for blending ethanol into 

gasoline as E10 and E85, and for 

blending biodiesel and renewable diesel 

with diesel fuel. The costs are expressed 

two different ways. First, we express the 

full ‘‘engineering’’ cost of the program 

without the ethanol consumption tax 

subsidies in which the costs are based 

on the total accumulated costs of each 

of the fuels changes, at both reference 

case and high crude oil prices. Second, 

we express the costs subtracting the 

ethanol and biodiesel and renewable 

diesel consumption tax subsidies since 

some or perhaps most of the cost of the 

tax subsidy may not be reflected in the 

price consumers pay at retail. In all 

cases, the capital costs are amortized at 

seven percent return on investment 

(ROI) before taxes, and based on 2006 

dollars. 

a. Costs Without Federal Tax Subsidies 

Table VIII.D.2–1 summarizes the costs 

without ethanol tax subsidies for each of 

the two control cases, including the cost 

for each aspect of the fuels changes, and 

the aggregated total and the per-gallon 

costs for all the fuel changes.475 This 

estimate of costs reflects the changes in 

gasoline that are occurring with the 

expanded use of renewable and 

alternative fuels. These costs include 

the labor, utility and other operating 

costs, fixed costs and the capital costs 

for all the fuel changes expected. The 

per-gallon costs are derived by dividing 

the total costs over all U.S. gasoline and 

diesel fuel projected to be consumed in 

2022. Note that these costs are 

incremental only to the reference case 

volumes of renewable fuels (costing out 

about 20 billion gallons of new 

renewable fuels) and does not reflect the 

costs of the renewable fuel volumes in 

the reference case. 

TABLE VIII.D.2–1—ESTIMATED COSTS OF THE RFS2 PROGRAM IN 2022 

[2006 dollars, 7% ROI before taxes] 

$53 per barrel of crude 

oil incremental to reference case 

$92 per barrel of crude 

oil incremental to reference case 

Gasoline Impacts .................................................................... $billion/yr ................................ 17 .0 4 .1 

c/gal ....................................... 10 .91 2 .65 

Diesel Fuel Impacts ................................................................ $billion/yr ................................ 0.78 ¥0 .05 

c/gal ....................................... 1 .20 ¥0 .07 

Total Impact ..................................................................... $billion/yr ................................ 17 .8 4 .1 

Our analysis shows, as expected, that 

the RFS2 program is more cost effective 

at the higher assumed price of crude oil. 

At our assumed crude oil price of $53 

per barrel, the gasoline and diesel fuel 

costs are projected to increase by $17.0 

billion and $0.78 billion, respectively, 

or $17.8 billion in total. Expressed as 

per-gallon costs, these fuel changes 

would increase the cost of producing 

gasoline and diesel fuel by 10.91 and 

1.20 cents per gallon, respectively. At 

the assumed crude oil price of $92 per 

barrel, the gasoline costs are projected to 

increase by $4.1 billion and the diesel 

fuel costs are projected to decrease by 

$0.05 billion, or increase by $4.1 billion 

in total. Expressed as per-gallon costs, 

these fuel changes would increase 

gasoline costs by 2.65 and decrease 

diesel fuel costs by 0.07 cents per gallon 

at the higher crude oil price. Our 

analysis shows that at the higher crude 

oil price, ethanol, biodiesel and 

renewable diesel fuel use would be 

much less costly to use. 

The increased use of renewable and 

alternative fuels would require capital 

investments in corn and cellulosic 

ethanol plants, and renewable diesel 

fuel plants. In addition to producing the 

fuels, storage and distribution facilities 

along the whole distribution chain, 

including at retail, will have to be 

constructed for these new fuels. 

Conversely, as these renewable and 

25086 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

476The recent economic bailout law increased the 

subsidy provided to renewable diesel fuel to $1 per 

gallon, but we were not able incorporate this change 

in time for this proposed rulemaking. 

alternative fuels are being produced, 

they supplant gasoline and diesel fuel 

demand which results in less new 

investments in refineries compared to 

business as usual. In Table VIII.D.2–2, 

we list the total incremental capital 

investments that we project would be 

made for this proposed RFS2 

rulemaking incremental to the AEO 

2007 reference case. 

TABLE VIII.D.2–2—TOTAL PROJECTED

U.S. CAPITAL INVESTMENTS FOR THE

RFS2 PROGRAM

[billion dollars] 

Plant Type Capital Costs 

Corn Ethanol ........................... 4 .0 

Cellulosic Ethanol ................... 50 .1 

Ethanol Distribution ................ 12 .4 

Bio/Renew Diesel Fuel Production and Distribution ...... 0 .25 

Refining ................................... ¥7 .9 

Total .................................... 58 .9 

Table VIII.D.2–2 shows that the total 

U.S. incremental capital investments 

attributed to this program for 2022 are 

$58.9 billion. One contributing reason 

why the capital investments made for 

renewable fuels technologies is so much 

more than the decrease in refining 

industry capital investments is that a 

large part of the decrease in petroleum 

gasoline supply was from reduced 

imports. In addition, renewable fuels 

technologies are more capital intensive 

per gallon of fuel produced than 

incremental increases in gasoline and 

diesel fuel production at refineries. 

b. Gasoline and Diesel Costs Reflecting 

the Tax Subsidies 

Table VIII.D.2–3 below expresses the 

total and per-gallon gasoline costs for 

the two control scenarios showing the 

effect of the Federal tax subsidies. The 

Federal tax subsidy is 45 cents per 

gallon for each gallon of new corn 

ethanol blended into gasoline and $1.01 

per gallon for each gallon of cellulosic 

ethanol. Imported ethanol also receives 

the 45 cents per gallon Federal tax 

subsidy, although the portion of 

imported ethanol which exceeds the 

volume of imported ethanol exempted 

through the Caribbean Basin Initiative 

(CBI) would have to pay a 51 cents per 

gallon tariff. We estimate that in 2022 

imported ethanol would receive a net 23 

cents per gallon subsidy after we 

account for both the subsidy and 

projected volume of imported ethanol 

subjected to the tariff. While there are 

also state ethanol tax subsidies we did 

not consider those subsidies. A $1 per 

gallon subsidy currently applies to 

biodiesel produced from virgin plant 

oils (i.e., soy) and a 50 cent per gallon 

subsidy applies to biodiesel and 

renewable diesel fuel produced from 

waste fats and oils; we assume that 

these subsidies continue.476 The 

subsidies, if passed along to the 

consumer, reduce the apparent cost of 

the program to the consumer at retail 

since part of the program cost is being 

paid through taxes. The cost reduction 

attributed to the subsidies is estimated 

by multiplying the value of the 

subsidies times the volume of new corn 

and cellulosic ethanol used in 

transportation fuels. 

TABLE VIII.D.2–3—ESTIMATED COSTS OF THE RFS2 PROGRAM IN 2022 

[Reflecting Tax Subsidies, 2006 dollars, 7% ROI before taxes] 

$53 per barrel of crude 

oil incremental to reference case 

$93 per barrel of crude 

oil incremental to reference case 

Gasoline Impacts .................................................................... $billion/yr ................................ ¥0 .74 ¥13 .6 

c/gal ....................................... ¥0 .48 ¥8 .74 

Diesel Fuel Impacts ................................................................ $billion/yr ................................ 0.25 ¥0 .57 

c/gal ....................................... 0 .39 ¥0 .88 

Total Impact ..................................................................... $billion/yr ................................ ¥0 .49 ¥14 .2 

Our analysis shows, as expected, that 

the overall costs of the RFS2 program 

appears to be lower when considering 

the ethanol consumption subsidies. At 

the assumed crude oil price of $53 per 

barrel, the gasoline and diesel fuel costs 

are projected to decrease by $0.74 

billion and increase $0.25 billion, 

respectively, or $¥0.49 billion in total. 

Expressed as per-gallon costs, these fuel 

changes would decrease gasoline costs 

by ¥0.48 cents per gallon and increase 

diesel fuel costs by 0.39 cents per 

gallon. At the assumed crude oil price 

of $92 per barrel, the gasoline and diesel 

fuel costs are projected to decrease by 

$13.6 billion and $0.57 billion, 

respectively, or $14.2 billion in total. 

Expressed as per-gallon costs, these fuel 

changes would decrease gasoline and 

diesel fuel by 8.74 and 0.88 cents per 

gallon, respectively. Reducing the cost 

by the tax subsidies, which more closely 

represents the prices paid by consumers 

at the pump, our analysis shows that at 

lower crude oil prices that the cost of 

the program would be very small. 

However, at the higher oil prices and 

including the subsidies, the program’s 

costs are very negative. 

IX. Economic Impacts and Benefits of 

the Proposal 

A. Agricultural Impacts 

EPA used two principal tools to 

model the potential domestic and 

international impacts of the RFS2 on the 

U.S. and global agricultural sectors. The 

Forest and Agricultural Sector 

Optimization Model (FASOM), 

developed by Professor Bruce McCarl of 

Texas A&M University and others, 

provides detailed information on 

domestic agricultural and greenhouse 

gas impacts of renewable fuels. The 

Food and Agricultural Policy Research 

Institute (FAPRI) at Iowa State 

University and the University of 

Missouri-Columbia maintains a number 

of econometric models that are capable 

of providing detailed information on 

impacts on international agricultural 

markets from the wider use of 

renewable fuels in the U.S. 

FASOM is a long-term economic 

model of the U.S. agriculture sector that 

attempts to maximize total revenues for 

producers while meeting the demands 

of consumers. FASOM can be utilized to 

estimate which crops, livestock, and 

processed agricultural products would 

be produced in the U.S. given RFS2 

biofuel requirements. In each model 

simulation, crops compete for price 

sensitive inputs such as land and labor 

at the regional level and the cost of 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25087 

these and other inputs are used to 

determine the price and level of 

production of primary commodities 

(e.g., field crops, livestock, and biofuel 

products). FASOM also estimates prices 

using costs associated with the 

processing of primary commodities into 

secondary products (e.g., converting 

livestock to meat and dairy, crushing 

soybeans to soybean meal and oil, etc.). 

FASOM does not capture short-term 

fluctuations (i.e., month-to-month, 

annual) in prices and production, 

however, as it is designed to identify 

long-term trends (i.e., five to ten years). 

The domestic results provided 

throughout this analysis incorporate the 

agricultural sector component of the 

FASOM model. 

The FASOM model also contains a 

forestry component. Running both the 

forestry and agriculture components of 

the model would show the interaction 

between these two sectors. However, the 

analysis for this proposal only shows 

the results from the agriculture 

component with no interaction from the 

forestry sector, as the forestry 

component of the model is in the 

process of being updated. We plan to 

utilize a complete version of the model 

for our analysis in the final rule, where 

agricultural land use impacts also affect 

forestry land use, and cellulosic ethanol 

produced from the forestry sector will 

affect cellulosic ethanol production in 

the agriculture sector. 

The FAPRI models are econometric 

models covering many agricultural 

commodities. These models capture the 

biological, technical, and economic 

relationships among key variables 

within a particular commodity and 

across commodities. They are based on 

historical data analysis, current 

academic research, and a reliance on 

accepted economic, agronomic, and 

biological relationships in agricultural 

production and markets. The 

international modeling system includes 

international grains, oilseeds, ethanol, 

sugar, and livestock models. In general, 

for each commodity sector, the 

economic relationship that supply 

equals demand is maintained by 

determining a market-clearing price for 

the commodity. In countries where 

domestic prices are not solved 

endogenously, these prices are modeled 

as a function of the world price using a 

price transmission equation. Since 

econometric models for each sector can 

be linked, changes in one commodity 

sector will impact other sectors. 

Elasticity values for supply and demand 

responses are based on econometric 

analysis and on consensus estimates. 

Additional information on the FASOM 

and FAPRI models is included in the 

Draft Regulatory Impact Analysis (DRIA 

Chapter 5). 

For the agricultural sector analysis 

using the FASOM and FAPRI models of 

the RFS2 biofuel volumes, we assumed 

15 billion gallons (Bgal) of corn ethanol 

would be produced for use as 

transportation fuel by 2022, an increase 

of 2.7 Bgal from the Reference Case. 

Also, we modeled 1.0 Bgal of biodiesel 

used as fuel in 2022, an increase of 0.6 

Bgal from the Reference Case. In 

addition, we modeled an increase of 10 

Bgal of cellulosic ethanol in 2022. In 

FASOM, this volume consists of 7.5 

billion gallons of cellulosic ethanol 

coming from corn residue in 2022, 1.3 

billion gallons from switchgrass and 1.4 

billion gallons from sugarcane bagasse. 

Though these volumes differ slightly 

from those analyzed in Section 

V.B.2.c.iv, we will work to align the 

volumes for the final rulemaking. 

Given the short timeframe for 

conducting this analysis, some of the 

projected sources of biofuels analyzed 

in the RFS2 proposal are not currently 

modeled in FASOM and FAPRI. For 

example, biodiesel from corn oil 

fractionation is not currently accounted 

for in FASOM. In addition, since 

FASOM is a domestic agricultural sector 

model, it can’t be utilized to examine 

the impacts of the wider use of biofuel 

imports into the U.S. Also, neither of 

the two models used for this analysis— 

FASOM or FAPRI—include biofuels 

derived from domestic municipal solid 

waste or from the U.S. forestry sector. 

Thus, for the RFS2 agricultural sector 

analysis, these biofuel sources are 

analyzed outside of the agricultural 

sector models. 

All the results presented in this 

section are relative to the AEO 2007 

Reference Case renewable fuel volumes, 

which include 12.3 Bgal of grain-based 

ethanol, 0.4 Bgal of biodiesel, and 0.3 

Bgal of cellulosic ethanol in 2022. The 

domestic figures are provided by 

FASOM, and all of the international 

numbers are provided by FAPRI. The 

detailed FASOM results, detailed FAPRI 

results, and additional sensitivity 

analyses are described in more detail in 

the DRIA. We seek comment on this 

analysis of the agricultural sector 

impacts resulting from the wider use of 

renewable fuels. 

TABLE IX.A.1–1—BIOFUEL VOLUMES MODELED IN 2022 

[Billions of Gallons] 

Biofuel Reference Case Control Case Change 

Corn Ethanol .................................................................................................................. 12 .3 15.0 2.7 

Corn Residue Cellulosic Ethanol ................................................................................... 0 7.5 7.5 

Sugarcane Bagasse Cellulosic Ethanol ........................................................................ 0 .3 1.4 1.1 

Switchgrass Cellulosic Ethanol ...................................................................................... 0 1.3 1.3 

Other Ethanol ................................................................................................................. 0 0.2 0.2 

Biodiesel ........................................................................................................................ 0 .4 1.0 0.6 

1. Commodity Price Changes 

For the scenario modeled, FASOM 

predicts that in 2022 U.S. corn prices 

would increase by $0.15 per bushel 

(4.6%) above the Reference Case price of 

$3.19 per bushel. By 2022, U.S. soybean 

prices would increase by $0.29 per 

bushel (2.9%) above the Reference Case 

price of $9.97 per bushel. The price of 

sugarcane would increase $13.34/ton 

(41%) above the Reference Case price of 

$32.49 per ton by 2022. In 2022, beef 

prices would increase $0.93 per 

hundred pounds (1.4%), relative to the 

Reference Case price of $67.72 per 

hundred pounds. Additional price 

impacts are included in Section 5.1.1 of 

the DRIA. 

TABLE IX.A.1–2—CHANGE IN U.S. 

COMMODITY PRICES FROM THE REFERENCE CASE

[2006$] 

Commodity Change % 

Change 

Corn ........... $0.15/bushel ......... 4.6 

Soybeans .. $0.29/bushel ......... 2.9 

Sugarcane $13.34/ton ............. 41 

25088 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

477Total U.S. planted acres increases to 92.2 

million acres from the Reference Case level of 89 

million acres in 2022. 

TABLE IX.A.1–2—CHANGE IN U.S. 

COMMODITY PRICES FROM THE REFERENCE CASE—Continued 

[2006$] 

Commodity Change % 

Change 

Fed Beef .... $0.93/hundred 

pounds.

1.4 

By 2022, the price of switchgrass is 

$30.18 per wet ton and the farm gate 

feedstock price of corn stover is $32.74/ 

wet ton. These prices do not include the 

storage, handling, or delivery costs, 

which would result in a delivered price 

to the ethanol facility of at least twice 

the farm gate cost, depending on the 

region. We intend to update the costs 

assumptions (described in more detail 

in Section 4.1.1 of the DRIA) for the 

final rule and invite comment on these 

assumptions. 

2. Impacts on U.S. Farm Income 

The increase in renewable fuel 

production provides a significant 

increase in net farm income to the U.S. 

agricultural sector. FASOM predicts that 

net U.S. farm income would increase by 

$7.1 billion dollars in 2022 (10.6%), 

relative to the AEO 2007 Reference 

Case. 

3. Commodity Use Changes 

Changes in the consumption patterns 

of U.S. corn can be seen by the 

increasing percentage of corn used for 

ethanol. FASOM estimates the amount 

of domestically produced corn used for 

ethanol in 2022 would increase to 33%, 

relative to the 28% usage rate under the 

Reference Case. The rising price of corn 

and soybeans in the U.S. would also 

have a direct impact on how corn is 

used. Higher domestic corn prices 

would lead to lower U.S. exports as the 

world markets shift to other sources of 

these products or expand the use of 

substitute grains. FASOM estimates that 

U.S. corn exports would drop 263 

million bushels (¥9.9%) to 2.4 billion 

bushels by 2022. In value terms, U.S. 

exports of corn would fall by $487 

million (¥5.7%) to $8 billion in 2022. 

U.S. exports of soybeans would also 

decrease under this proposal. FASOM 

estimates that U.S. exports of soybeans 

would decrease 96.6 million bushels 

(¥9.3%) to 943 million bushels by 

2022. In value terms, U.S. exports of 

soybeans would decrease by $691 

million (¥6.7%) to $9.7 billion in 2022. 

TABLE IX.A.3–1—REDUCTIONS IN U.S. EXPORTS FROM THE REFERENCE CASE IN 2022 

Exports Change % Change 

Corn in Bushels .......................................................................... 263 million .................................................................................. ¥9.9 

Soybeans in Bushels .................................................................. 96.6 million ................................................................................. ¥9.3 

Total Value of Exports Change % Change 

Corn (2006$) .............................................................................. $487 million ................................................................................ ¥5.7 

Soybeans (2006$) ...................................................................... $691 million ................................................................................ ¥6.7 

Higher U.S. demand for corn for 

ethanol production would cause a 

decrease in the use of corn for U.S. 

livestock feed. Substitutes are available 

for corn as a feedstock, and this market 

is price sensitive. Several ethanol 

processing byproducts could also be 

used to replace a portion of the corn 

used as feed, depending on the type of 

animal. Distillers dried grains with 

solubles (DDGS) are a byproduct of dry 

milling ethanol production, and gluten 

meal and gluten feed are byproducts of 

wet milling ethanol production. By 

2022, FASOM predicts ethanol 

byproducts used in feed would increase 

19% to 30 million tons, compared to 25 

million tons under the Reference Case. 

TABLE IX.A.3–2—PERCENT CHANGE

IN ETHANOL BYPRODUCTS USE IN

FEED RELATIVE TO THE REFERENCE

CASE

Category 2022 

Ethanol Byproducts .................. 19% 

The EISA cellulosic ethanol 

requirements result in the production of 

residual agriculture products as well as 

dedicated energy crops. By 2022, 

FASOM predicts production of 90 

million tons of corn residue and 18 

million tons of switchgrass. Sugarcane 

bagasse for cellulosic ethanol 

production increases by 15.7 million 

tons to 19.7 million tons in 2022 relative 

to the Reference Case. 

4. U.S. Land Use Changes 

Higher U.S. corn prices would have a 

direct impact on the value of U.S. 

agricultural land. As demand for corn 

and other farm products increases, the 

price of U.S. farm land would also 

increase. Our analysis shows that land 

prices would increase by about 21% by 

2022, relative to the Reference Case. 

FASOM estimates an increase of 3.2 

million acre increase (3.9%) in 

harvested corn acres, relative to 83.4 

million acres harvested under the 

Reference Case by 2022.477 Most of the 

new corn acres come from a reduction 

in existing crop acres, such as rice, 

wheat, and hay. 

Though demand for biodiesel 

increases, FASOM predicts a fall in U.S. 

soybean acres harvested, assuming 

soybean-based biodiesel meets the EISA 

GHG emission reduction thresholds. 

According to the model, harvested 

soybean acres would decrease by 

approximately 0.4 million acres 

(¥0.5%), relative to the Reference Case 

acreage of 71.5 million acres in 2022. 

Despite the decrease in soybean acres in 

2022, soybean oil production would 

increase by 0.4 million tons (4.0%) by 

2022 over the Reference Case. 

Additionally, FASOM predicts that 

soybean oil exports would decrease 1.3 

million tons by 2022 (¥52%) relative to 

the Reference Case. 

As the demand for cellulosic ethanol 

increases, most of the production is 

derived from corn residue harvesting. 

As demand for cellulosic ethanol from 

bagasse increases, sugarcane acres 

increase by 0.7 millions acres (55%) to 

1.9 million acres by 2022. In addition, 

some of the cellulosic ethanol comes 

from switchgrass, which is not 

produced under the Reference Case. In 

the scenario analyzed, 2.8 million acres 

of switchgrass will be planted by 2022. 

As described in Section V, for both the 

Reference Case and the Control Case, we 

assume 32 million acres would remain 

in the Conservation Reserve Program 

(CRP). Therefore, some of the new corn, 

soybean, and switchgrass acres may be 

indirectly coming from former CRP land 

that is not re-enrolled in the program. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25089 

478FASOM does not calculate changes in price to 

the consumer directly. The proxy for aggregate food 

price change is an indexed value of all food prices 

at the farm gate. It should be noted, however, that 

according to USDA, approximately 80% of 

consumer food expenditures are a result of handling 

after it leaves the farm (e.g., processing, packaging, 

storage, marketing, and distribution). These costs 

consist of a complex set of variables, and do not 

necessarily change in proportion to an increase in 

farm gate costs. In fact, these intermediate steps can 

absorb price increases to some extent, suggesting 

that only a portion of farm gate price changes are 

typically reflected at the retail level. See http:// 

www.ers.usda.gov/publications/foodreview/ 

septdec00/FRsept00e.pdf. 

479These estimates are based on U.S. Census 

population projections of 318 million people in 

2017 and 330 million people in 2022. See http:// 

www.census.gov/population/www/projections/ 

natsum.html. 

480Farm Gate food prices refer to the prices that 

farmers are paid for their commodities. 

481See www.ers.usda.gov/Briefing/ 

CPIFoodAndExpenditures/Data/table15.htm. 

TABLE IX.A.4–1—CHANGE IN U.S. 

CROP ACRES RELATIVE TO THE

REFERENCE CASE IN 2022 

[Millions of acres] 

Crop Change % Change 

Corn .................. 3.2 3.9 

Soybeans .......... ¥0.4 ¥0.5 

Sugarcane ........ 0.7 55 

Switchgrass ...... 2.8 N/A 

The additional demand for corn and 

other crops for biofuel production also 

results in increased use of fertilizer in 

the U.S. In 2022, FASOM estimates that 

U.S. nitrogen fertilizer use would 

increase 897 million pounds (3.4%) 

over the Reference Case nitrogen 

fertilizer use of 26.2 billion pounds. In 

2022, U.S. phosphorous fertilizer use 

would increase by 496 million pounds 

(8.6%) relative to the Reference Case 

level of 5.8 billion pounds. 

TABLE IX.A.4–2—CHANGE IN U.S. 

FERTILIZER USE RELATIVE TO THE

REFERENCE CASE

[Millions of pounds] 

Fertilizer Change % Change 

Nitrogen ............ 897 3.4 

Phosphorous ..... 496 8.6 

5. Impact on U.S. Food Prices 

Due to higher commodity prices, 

FASOM estimates that U.S. food 

costs 478 would increase by roughly $10 

per person per year by 2022, relative to 

the Reference Case.479 Total effective 

farm gate food costs would increase by 

$3.3 billion (0.2%) in 2022.480 To put 

these changes in perspective, average 

U.S. per capita food expenditures in 

2007 were $3,778 or approximately 10% 

of personal disposable income. The total 

amount spent on food in the U.S. in 

2007 was $1.14 trillion dollars.481

6. International Impacts 

Changes in the U.S. agriculture 

economy are likely to have effects in 

other countries around the world in 

terms of trade, land use, and the global 

price and consumption of fuel and food. 

We utilized the FAPRI model to assess 

the impacts of the increased use of 

renewable fuels in the U.S. on world 

agricultural markets. 

The FAPRI modeling shows that 

world corn prices would increase by 

7.5% to $3.69 per bushel in 2022, 

relative to the Reference Case. The 

impact on world soybean prices is 

somewhat smaller, increasing 5.6% to 

$9.94 per bushel in 2022. 

Changes to the global commodity 

trade markets and world commodity 

prices result in changes in international 

land use. The FAPRI model provides 

international change in crop acres as a 

result of the RFS2 proposal. Brazil has 

the largest positive change in crop acres 

in 2022, followed by the U.S., Nigeria, 

India, Paraguay, and China. The FAPRI 

model estimates that Brazil crop acres 

increase by 3.1 million acres (2.0%) to 

153.6 million acres relative to the 

Reference Case. Total U.S. acres 

increase by 2.3 million acres (1.0%) in 

2022 to 232.6 million acres. Nigeria has 

an increase in crop acres of 1.5 million 

acres (5.9%) to 27.3 million acres in 

2022. India’s total crop acres increase by 

1.0 million acres (0.3%) to 326 million 

acres in 2022. Total crop acres in 

Paraguay increase by 0.8 million acres 

(6.9%) to 12 million acres. China’s total 

crop acres increase by 0.4 million acres 

(0.2%) to 257.8 million acres in 2022. 

BILLING CODE 6560–50–P 

25090 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

482The food commodities included in the FAPRI 

model include corn, wheat, sorghum, barley, 

soybeans, sugar, peanuts, oils, beef, pork, poultry, 

and dairy products. 

483Bureau of Economic Affairs: ‘‘U.S. 

International Transactions, Fourth Quarter of 2007’’ 

by Elena L. Nguyen and Jessica Melton Hanson, 

April 2008. 

484 Davis, Stacy C.; Diegel, Susan W., 

Transportation Energy Data Book: 25th Edition, Oak 

Ridge National Laboratory, U.S. Department of 

Energy, ORNL–6974, 2006. 

The RFS2 proposal results in higher 

international commodity prices, which 

would impact world food 

consumption.482 The FAPRI model 

indicates that world consumption of 

corn for food would decrease by 1.1 

million metric tons in 2022 relative to 

the Reference Case. Similarly, the 

FAPRI model estimates that world 

consumption of wheat for food would 

decrease by 0.6 million metric tons in 

2022. World consumption of oil for food 

(e.g., vegetable oils) decreases 1.8 

million metric tons by 2022. The model 

also estimates a small change in world 

meat consumption, decreasing by 0.3 

million metric tons in 2022. When 

considering all the food uses included 

in the model, world food consumption 

decreases by 0.9 million metric tons by 

2022 (¥0.04%). While FAPRI provides 

estimates of changes in world food 

consumption, estimating effects on 

global nutrition is beyond the scope of 

this analysis. 

TABLE IX.A.6–1—CHANGE IN WORLD

FOOD CONSUMPTION RELATIVE TO

THE REFERENCE CASE

[Millions of metric tons] 

Category 2022 

Corn .......................................... ¥1.1 

Wheat ....................................... ¥0.6 

Vegetable Oils .......................... ¥1.8 

Meat .......................................... ¥0.3 

Total Food ............................. ¥0.9 

Additional information on the U.S. 

agricultural sector and international 

trade impacts of this proposal is 

described in more detail in the DRIA 

(Chapter 5). 

B. Energy Security Impacts 

Increasing usage of renewable fuels 

helps to reduce U.S. petroleum imports. 

A reduction of U.S. petroleum imports 

reduces both financial and strategic 

risks associated with a potential 

disruption in supply or a spike in cost 

of a particular energy source. This 

reduction in risks is a measure of 

improved U.S. energy security. In this 

section, we estimate the monetary value 

of the energy security benefits of the 

RFS2 mandated volumes in comparison 

to the Reference Case by estimating the 

impact of the expanded use of 

renewable fuels on U.S. oil imports and 

avoided U.S. oil import expenditures. In 

the second section, a methodology is 

described for estimating the energy 

security benefits of reduced U.S. oil 

imports. The final section summarizes 

the energy security benefits to the U.S. 

associated with this proposal. 

1. Implications of Reduced Petroleum 

Use on U.S. Imports 

In 2007, U.S. petroleum imports 

represented 19.5% of total U.S. imports 

of all goods and services.483 In 2005, the 

United States imported almost 60% of 

the petroleum it consumed. This 

compares roughly to 35% of petroleum 

from imports in 1975.484 Transportation 

accounts for 70% of the U.S. petroleum 

consumption. It is clear that petroleum 

imports have a significant impact on the 

U.S. economy. Diversifying 

transportation fuels in the U.S. is 

expected to lower U.S. petroleum 

imports. To estimate the impacts of this 

proposal on the U.S.’s dependence on 


EP26MY09.011</GPH>
Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25091 

485Leiby, Paul N., Donald W. Jones, T. Randall 

Curlee, and Russell Lee, Oil Imports: An 

Assessment of Benefits and Costs, ORNL–6851, Oak 

Ridge National Laboratory, November, 1997. 

486The 1997 ORNL paper was cited and its 

results used in DOT/NHTSA’s rules establishing 

CAFE standards for 2008 through 2011 model year 

light trucks. See DOT/NHTSA, Final Regulatory 

Impacts Analysis: Corporate Average Fuel Economy 

and CAFE Reform MY 2008–2011, March 2006. 

487Leiby, Paul N. ‘‘Estimating the Energy Security 

Benefits of Reduced U.S. Oil Imports,’’ Oak Ridge 

Continued 

imported oil, we calculate avoided U.S. 

expenditures on petroleum imports. 

For the proposal, EPA analyzed two 

approaches to estimate the reductions in 

U.S. petroleum imports. The first 

approach utilizes a model of the U.S. 

energy sector, the National Energy 

Modeling System (NEMS), to quantify 

the type and volume of reduced 

petroleum imports based on supply and 

demand for specific fuels in a given 

year. The National Energy Modeling 

System (NEMS) is a computer-based, 

energy-economy modeling system of 

U.S. energy markets through the 2030 

time period. NEMS projects U.S. 

production, imports, conversion, 

consumption, and prices of energy; 

subject to assumptions on world energy 

markets, resource availability and costs, 

behavioral and technological choice 

criteria, cost and performance 

characteristics of energy technologies, 

and demographics. NEMS is designed 

and implemented by the Energy 

Information Administration (EIA) of the 

U.S. Department of Energy (DOE). For 

this analysis, the NEMS model was run 

with the 2007 AEO levels of biofuels in 

the Reference Case compared with the 

biofuel volume RFS2 requirements. 

Considering the regional nature of 

U.S. imports of petroleum imports, a 

second approach was utilized as well to 

estimate the impacts of the RFS2 

proposal on U.S. oil imports. This 

approach is labeled ‘‘Regional Gasoline 

Market’’ approach. This approach makes 

the assumption that one half of the 

ethanol market is in the Northeast 

region of the U.S., which also comprises 

about half of the nation’s gasoline 

demand. For this analysis, it is 

estimated that ethanol would displace 

imported gasoline or gasoline blend 

stocks in the Northeast, but not 

elsewhere in the country. Therefore, to 

derive the portion of the new renewable 

fuels which would offset U.S. petroleum 

imports (and not impact domestic 

refinery production), we multiplied the 

total volume of petroleum fuel 

displaced by 50 percent to represent 

that portion of the ethanol which would 

be used in the Northeast, and 50 percent 

again to only account for that which 

would offset imports. The rest of the 

ethanol, including half of the ethanol 

presumed to be used in the Northeast, 

is presumed to offset domestic gasoline 

production, which ultimately offsets 

crude oil inputs at refineries. Biodiesel 

and renewable diesel are presumed to 

offset domestic diesel fuel production. 

The results shown in Table IX.B.1–1 

below reflect the net lifecycle 

reductions in U.S. oil imports projected 

by NEMS. The net lifecycle reductions 

include the upstream petroleum used to 

produce renewable fuels, gasoline and 

diesel, as well as the petroleum directly 

used by end-users. 

TABLE IX.B.1–1—NET REDUCTIONS IN

OIL IMPORTS IN 2022 (NEMS 

MODEL RESULTS) 

[Millions of barrels per day] 

Category of reduction 2022 

Imports of Finished Petroleum 

Products ................................ 0.823 

Imports of Crude Oil ................. (0.007) 

Total Reduction ........................ 0.815 

Percent Reduction .................... 6.15% 

The NEMS model projects that for the 

year 2022 all of the reduction in 

petroleum imports comes out of 

finished petroleum products. NEMS 

projects that 91% of the reductions in 

2022 come from reduced net imports of 

crude oil and finished petroleum 

products (as compared to a 9% 

reduction in domestic U.S. production). 

The results shown in Table IX.B.1–2 

below reflect the net lifecycle 

reductions in U.S. oil imports projected 

by the use of the Regional Gasoline 

Market approach detailed above. 

TABLE IX.B.1–2—NET REDUCTIONS IN

OIL IMPORTS IN 2022 (REGIONAL

GASOLINE MARKET APPROACH RESULTS) 

[Millions of barrels per day] 

Category of reduction 2022 

Imports of Finished Petroleum 

Products ................................ 0.250 

Imports of Crude Oil ................. 0.637 

Total Reduction ........................ 0.887 

Percent Reduction .................... 6.17% 

The Regional Gasoline Market 

approach projects that for 2022, 72% of 

the petroleum supply displacement (on 

a volume basis) comes out of reduced 

net crude oil imports, and 28% out of 

net imports of finished petroleum 

products (excluding biofuels). Using our 

two approaches for projecting total 

petroleum import reductions (the NEMS 

and the Regional Gasoline Market), we 

estimate that petroleum product imports 

will fall between 0.815 to 0.887 million 

barrels per day in 2022 as a result of the 

RFS2 proposal. 

Using the NEMS model, we also 

calculated the change in expenditures in 

both U.S. petroleum and ethanol 

imports with the RFS2 proposal and 

compared these with the U.S. trade 

position measured as U.S. net exports of 

all goods and services economy-wide. 

Changes in fuel expenditures were 

estimated by multiplying the changes in 

gasoline, diesel, and ethanol net imports 

by the respective AEO 2008 wholesale 

gasoline and distillate price forecasts, 

and ethanol price forecasts from the 

Food and Agricultural Policy Research 

Institute (FAPRI) for the specific 

analysis years. In Table IX.B.1–3, the net 

expenditures in reduced petroleum 

imports and increased ethanol imports 

are compared to the total value of U.S. 

net exports of goods and services for the 

whole economy for 2022. The U.S. net 

exports of goods and services estimates 

are taken from Energy Information 

Administration’s Annual Energy 

Outlook 2008. We project that avoided 

expenditures on imported petroleum 

products due to this proposal would be 

roughly $16 billion in 2022. Relative to 

the 2022 projection, the total avoided 

expenditures on liquid transportation 

fuels are projected to be $12.4 billion 

with the RFS2 proposal. 

TABLE IX.B.1–3—CHANGES IN EXPENDITURES ON TRANSPORTATION

FUEL NET IMPORTS

[Billions of 2006$] 

Category 2022 

AEO Total Net Exports ........... 16 

Expenditures on Net Petroleum Imports ....................... (15.96 ) 

Expenditures on Net Ethanol 

and Biodiesel Imports ......... 3.52 

Net Expenditures on Transportation Fuel Imports ......... (12.44 ) 

2. Energy Security Implications 

In order to understand the energy 

security implications of reducing U.S. 

oil imports, EPA has worked with Oak 

Ridge National Laboratory (ORNL), 

which has developed approaches for 

evaluating the social costs and energy 

security implications of oil use. In a 

new study entitled ‘‘The Energy Security 

Benefits of Reduced Oil Use, 2006– 

2015,’’ completed in February, 2008, 

ORNL has updated and applied the 

analytical approach used in the 1997 

Report ‘‘Oil Imports: An Assessment of 

Benefits and Costs.’’ 485 486 This new 

study is included as part of the record 

in this rulemaking.487

25092 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

National Laboratory, ORNL/TM–2007/028, Final 

Report, 2008. 

488Peer Review Report Summary: Estimating the 

Energy Security Benefits of Reduced U.S. Oil 

Imports, ICF, Inc., September 2007. 

The approach developed by ORNL 

estimates the incremental benefits to 

society, in dollars per barrel, of reducing 

U.S. oil imports, called the ‘‘oil 

premium.’’ Since the 1997 publication 

of the ORNL Report, changes in oil 

market conditions, both current and 

projected, suggest that the magnitude of 

the oil premium has changed. 

Significant driving factors that have 

been revised include: Oil prices, current 

and anticipated levels of OPEC 

production, U.S. import levels, the 

estimated responsiveness of regional oil 

supplies and demands to price, and the 

likelihood of oil supply disruptions. For 

this analysis, oil prices from the AEO 

2007 were used. Using the ‘‘oil 

premium’’ approach, the analysis 

calculates estimates of benefits of 

improved energy security from reduced 

U.S. oil imports due to this proposal. 

When conducting this analysis, ORNL 

considered the full economic cost of 

importing petroleum into the U.S. The 

full economic cost of importing 

petroleum into the U.S. is defined for 

this analysis to include two components 

in addition to the purchase price of 

petroleum itself. These are: (1) The 

higher costs for oil imports resulting 

from the effect of U.S. import demand 

on the world oil price and OPEC market 

power (i.e., the ‘‘demand’’ or 

‘‘monopsony’’ costs); and (2) the risk of 

reductions in U.S. economic output and 

disruption of the U.S. economy caused 

by sudden disruptions in the supply of 

imported oil to the U.S. (i.e., 

macroeconomic disruption/adjustment 

costs). Maintaining a U.S. military 

presence to help secure stable oil supply 

from potentially vulnerable regions of 

the world was excluded from this 

analysis because its attribution to 

particular missions or activities is 

difficult. 

Also excluded from the prior analysis 

was risk-shifting that might occur as the 

U.S. reduces its dependency on 

petroleum and increases its use of 

biofuels. The analysis to date focused on 

the potential for biofuels to reduce oil 

imports, and the resulting implications 

of lower imports for energy security. 

The Agency recognizes that as the U.S. 

relies more heavily on biofuels, such as 

corn-based ethanol, there could be 

adverse consequences from a supplydisruption associated with, for example, 

a long-term drought. While the causal 

factors of a supply-disruption from 

imported petroleum and, alternatively, 

biofuels, are likely to be unrelated, 

diversifying the sources of U.S. 

transportation fuel will provide energy 

security benefits. The Agency was not 

able to conduct an analysis of biofuel 

supply disruption issue for this 

proposal. 

Between today’s proposal and the 

final rulemaking, EPA will attempt to 

broaden our energy security analysis to 

incorporate estimates of overall motor 

fuel supply and demand flexibility and 

reliability, and impacts of possible 

agricultural sector market disruptions 

(for example, a drought) for presentation 

in the final rule. The expanded analysis 

will also consider how the use of 

biofuels can alter short and long run 

elasticity (flexibility) in the motor fuel 

market, with implications for robustness 

of the fuel system in the face of diverse 

supply shocks. As part of this analysis, 

the Agency plans on analyzing those 

factors that can cause shifts in the prices 

of biofuels, and the impact these factors 

have on the energy security estimate. 

EPA sponsored an independentexpert peer review of the most recent 

ORNL study. A report compiling the 

peer reviewers’ comments is provided 

in the docket.488 In addition, EPA has 

worked with ORNL to address 

comments raised in the peer review and 

develop estimates of the energy security 

benefits associated with a reduction in 

U.S. oil imports for this proposal. In 

response to peer reviewer comments, 

EPA modified the ORNL model by 

changing several key parameters 

involving OPEC supply behavior, the 

responsiveness of oil demand and 

supply to a change in the world oil 

price, and the responsiveness of U.S. 

economic output to a change in the 

world oil price. EPA is soliciting 

comments on how to incorporate 

additional peer reviewer comments into 

the ORNL energy security analysis. (See 

the DRIA, Chapter 5, for more 

information on how EPA responded to 

peer reviewer comments.) 

With these changes for this proposal, 

ORNL has estimated that the total 

energy security benefits associated with 

a reduction of imported oil is $12.38/ 

barrel. Based upon alternative 

sensitivities about OPEC supply 

behavior and the responsiveness of oil 

demand and supply to a change in the 

world oil price, the energy security 

premium ranged from $7.65 to $17.23/ 

barrel. Highlights of the analysis are 

described below. 

a. Effect of Oil Use on Long-Run Oil 

Price, U.S. Import Costs, and Economic 

Output 

The first component of the full 

economic costs of importing petroleum 

into the U.S. follows from the effect of 

U.S. import demand on the world oil 

price over the long-run. Because the 

U.S. is a sufficiently large purchaser of 

foreign oil supplies, its purchases can 

affect the world oil price. This 

monopsony power means that increases 

in U.S. petroleum demand can cause the 

world price of crude oil to rise, and 

conversely, that reduced U.S. petroleum 

demand can reduce the world price of 

crude oil. Thus, one benefit of 

decreasing U.S. oil purchases is the 

potential decrease in the crude oil price 

paid for all crude oil purchased. ORNL 

estimates this component of the energy 

security benefit to be $7.65/barrel of 

U.S. oil imports reduced. A number of 

the peer reviewers suggested a variety of 

ways OPEC and other oil market 

participants might react to a decrease in 

the quantity of oil purchased by the U.S. 

ORNL has attempted to reflect a variety 

of possible market reactions in the 

analysis, but continues to evaluate ways 

to more explicitly model OPEC and 

other market participants’ behavior. 

EPA welcomes comments on this issue. 

Based upon alternative sensitivities 

about OPEC supply behavior, the priceresponsiveness of combined non-OPEC, 

non-U.S. supply and demand and a 

lower GDP elasticity with respect to 

disrupted oil prices, the monopsony 

premium ranged from $3.35–$12.45/ 

barrel of U.S. imported oil reduced. 

EPA recognizes that as the world 

price of oil falls in response to lower 

U.S. demand for oil, there is the 

potential for an increase in oil use 

outside the U.S. This so-called 

international oil ‘‘take back’’ or 

‘‘rebound’’ effect is hard to estimate. 

Given that oil consumption patterns 

vary across countries, there will be 

different demand responses to a change 

in the world price of crude oil. For 

example, in Europe, the price of crude 

oil comprises a much smaller portion of 

the overall fuel prices seen by 

consumers than in the U.S. Since 

Europeans pay significantly more than 

their U.S. counterparts for 

transportation fuels, a decline in the 

price of crude oil is likely to have a 

smaller impact on demand. In many 

other countries, particularly developing 

countries, such as China and India, oil 

is used more widely in industrial and 

even electricity applications, although 

China and India’s energy picture is 

evolving rapidly. In addition, many 

countries around the world subsidize 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25093 

489Stanford Energy Modeling Forum, Phillip C. 

Beccue and Hillard G. Huntington, ‘‘An Assessment 

of Oil Market Disruption Risks,’’ Final Report, EMF 

SR 8, October, 2005. 

their oil consumption. It is not clear 

how oil consumption would change due 

to changes in the market price of oil 

with the current pattern of subsidies. 

Emerging trends in worldwide oil 

consumption patterns illustrates the 

difficulty in trying to estimate the 

overall effect of a reduction in world oil 

price. However, the Agency recognizes 

that this effect is important to capture 

and is examining methodologies for 

quantifying this effect. EPA is exploring 

the development of this effect at the 

regional and country level in an effort 

to capture the net effect of different 

drivers. For example, a lower world oil 

price might encourage consumption of 

oil, but a country might deploy 

programs and policies discouraging oil 

consumption, which would have the net 

effect of lowering oil consumption to 

some level less than otherwise would be 

expected. EPA solicits comments on 

how to estimate this effect. 

b. Short-Run Disruption Premium From 

Expected Costs of Sudden Supply 

Disruptions 

The second component of the external 

economic costs resulting from U.S. oil 

imports arises from the vulnerability of 

the U.S. economy to oil shocks. The cost 

of shocks depends on their likelihood, 

size, and length; the capabilities of the 

market and U.S. Strategic Petroleum 

Reserve (SPR), the largest stockpile of 

government-owned emergency crude oil 

in the world, to respond; and the 

sensitivity of the U.S. economy to 

sudden price increases. While the total 

vulnerability of the U.S. economy to oil 

price shocks depends on the levels of 

both U.S. petroleum consumption and 

imports, variation in import levels or 

demand flexibility can affect the 

magnitude of potential increases in oil 

price due to supply disruptions. 

Disruptions are uncertain events, so the 

costs of alternative possible disruptions 

are weighted by disruption 

probabilities. The probabilities used by 

the ORNL study are based on a 2005 

Energy Modeling Forum 489 synthesis of 

expert judgment and are used to 

determine an expected value of 

disruption costs, and the change in 

those expected costs given reduced U.S. 

oil imports. ORNL estimates this 

component of the energy security 

benefit to be $4.74/barrel of U.S. 

imported oil reduced. Based upon 

alternative sensitivities about OPEC 

supply behavior, the priceresponsiveness of combined non-OPEC, 

non-U.S. supply and demand and a 

lower GDP elasticity with respect to 

disrupted oil prices, the macroeconomic 

disruption premium ranged from $2.64– 

$6.96/barrel of U.S. imported oil 

reduced. EPA continues to review 

recent literature on the macroeconomic 

disruption premium and welcomes 

comment on this issue. 

c. Costs of Existing U.S. Energy Security 

Policies 

Another often-identified component 

of the full economic costs of U.S. oil 

imports is the cost to the U.S. taxpayers 

of existing U.S. energy security policies. 

The two primary examples are 

maintaining a military presence to help 

secure stable oil supply from potentially 

vulnerable regions of the world and 

maintaining the SPR to provide buffer 

supplies and help protect the U.S. 

economy from the consequences of 

global oil supply disruptions. 

U.S. military costs are excluded from 

the analysis performed by ORNL 

because their attribution to particular 

missions or activities is difficult. Most 

military forces serve a broad range of 

security and foreign policy objectives. 

Attempts to attribute some share of U.S. 

military costs to oil imports are further 

challenged by the need to estimate how 

those costs might vary with incremental 

variations in U.S. oil imports. Similarly, 

while the costs for building and 

maintaining the SPR are more clearly 

related to U.S. oil use and imports, 

historically these costs have not varied 

in response to changes in U.S. oil 

import levels. Thus, while SPR is 

factored into the ORNL analysis, the 

cost of maintaining the SPR is excluded. 

A majority of the peer reviewers 

agreed with the exclusion of military 

expenditures from the current premium 

analysis primarily because of the 

difficulty in defining and measuring 

how military programs and 

expenditures might respond to 

incremental changes in U.S. oil imports. 

One reviewer clearly opposed including 

military costs on principle, and one peer 

reviewer clearly supported their 

inclusion if they could be shown to vary 

with import levels. The matter of 

whether military needs and programs 

can and do vary with U.S. oil imports 

or consumption levels would require 

careful consideration and analysis. It 

also calls for expertise in areas outside 

the scope of the peer review such as 

national security and military affairs. 

EPA solicits comment in this area. 

d. Anticipated Future Effort 

Between the proposal and the final 

rule, EPA intends to undertake a variety 

of actions to improve its energy security 

premium estimates. For the monopsony 

premium, we intend to develop energy 

security premiums with alternative AEO 

oil price cases (e.g., Reference, High, 

Low), develop a dynamic analysis 

methodology (i.e., how the energy 

security premium evolves through 

time), and assess and apply literature on 

OPEC strategic behavior/gaming models 

where possible. For the macroeconomic 

disruption impacts, EPA intends to 

examine recent literature on the 

elasticity of GDP to the oil price. Based 

upon that literature review, we intend to 

determine whether there is a difference 

in macro disruption impacts in the pre2000 and post-2000 time period. 

Further, we intend to break down the 

macroeconomic disruption costs by GDP 

losses and oil import costs. 

EPA solicits comments on the energy 

security analysis in a number of areas. 

Specifically, EPA is requesting comment 

on its interpretation of ORNL’s results, 

ORNL’s methodology, the monopsony 

effect, and the macroeconomic 

disruption effect. 

e. Total Energy Security Benefits 

Total annual energy security benefits 

associated with this proposal were 

derived from the estimated reductions 

in imports of finished petroleum 

products and crude oil using an energy 

security premium price of $12.38/barrel 

of reduced U.S. oil imports. Based on 

these values, we estimate that the total 

annual energy security benefits would 

be $3.7 billion in 2022 (in 2006 dollars). 

C. Benefits of Reducing GHG Emissions 

1. Introduction 

The wider use of renewable fuels from 

this proposal results in reductions in 

greenhouse gas (GHG) emissions. 

Carbon dioxide (CO2) and other GHGs 

mix well in the atmosphere, regardless 

of the location of the source, with each 

unit of emissions affecting global 

regional climates; and therefore, 

influencing regional biophysical 

systems. The effects of changes in GHG 

emissions are felt for decades to 

centuries given the atmospheric 

lifetimes of GHGs. This section provides 

estimates for the marginal and total 

benefits that could be monetized for the 

projected GHG emissions reductions of 

the proposal. EPA requests comment on 

the approach utilized to estimate the 

GHG benefits associated with the 

proposal. 

2. Marginal GHG Benefits Estimates 

The projected net GHG emissions 

reductions associated with the proposal 

reflect an incremental change to 

projected total global emissions. 

25094 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

490For background on economic principles and 

the marginal benefit estimates, see Technical 

Support Document on Benefits of Reducing GHG 

Emissions, U.S. Environmental Protection Agency, 

June 12, 2008, www.regulations.gov (search phrase 

‘‘Technical Support Document on Benefits of 

Reducing GHG Emissions’’). 

491See Table IX.C.1 for global (FUND) estimates 

consistent with the U.S. estimates. 

492The IPCC suggests an increase of 2–4% per 

year (IPCC WGII, 2007. Climate Change 2007— 

Impacts, Adaptation and Vulnerability. 

Contribution of Working Group II to the Fourth 

Assessment Report of the IPCC, http:// 

www.ipcc.ch/). For Table IX.C.1., we assumed the 

estimates increased at 3% per year. For the final 

rule, we anticipate that we will explicitly estimate 

FUND marginal benefits values for each emissions 

reduction year. 

493Tol (2008) is an update of the Tol (2005) meta 

analysis. Tol (2005) was used in the IPCC Working 

Group II’s Fourth Assessment Report (IPCC WGII, 

2007). 

494OMB and EPA guidance on inter-generational 

discounting suggests using a low but positive 

discount rate if there are important 

intergenerational benefits/costs. Consumption 

discount rates of 1–3% are given by OMB and 0.5– 

3% by EPA (OMB Circular A–4, 2003; EPA 

Guidelines for Preparing Economic Analyses, 2000). 

495E.g., Webster, M., C. Forest, J.M. Reilly, M.H. 

Babiker, D.W. Kicklighter, M. Mayer, R.G. Prinn, M. 

Sarofim, A.P. Sokolov, P.H. Stone & C. Wang, 2003. 

Uncertainty Analysis of Climate Change and Policy 

Response, Climatic Change 61(3): 295–320. Also, 

see Weitzman, M., 2007, ‘‘The Stern Review of the 

Economics of Climate Change,’’ Journal of 

Economic Literature. Weitzman, M., 2007, 

‘‘Structural Uncertainty and the Statistical Life in 

the Economics of Catastrophic Climate Change,’’ 

Working paper http://econweb.fas.harvard.edu/ 

faculty/weitzman/papers/ValStatLifeClimate.pdf. 

Therefore, as shown in Section VI.G, the 

projected global climate signal will be 

small but discernable (i.e., 

incrementally lower projected 

distribution of global mean surface 

temperatures). Given that the climate 

response is projected to be a marginal 

change relative to the baseline climate, 

it is conceptually appropriate to use an 

approach that estimates the marginal 

value of changes in climate change 

impacts over time as an estimate for the 

monetized marginal benefit of the GHG 

emissions reductions projected for this 

proposal. The marginal value of carbon 

is equal to the net present value of 

climate change impacts over hundreds 

of years of one additional net global 

metric ton of GHGs emitted to the 

atmosphere at a particular point in time. 

This marginal value (i.e., cost) of carbon 

is sometimes referred to as the ‘‘social 

cost of carbon.’’ 

Based on the global implications of 

GHGs and the economic principles that 

follow, EPA has developed ranges of 

global, as well as U.S., marginal benefits 

estimates (Table IX.C.2–1).490 It is 

important to note at the outset that the 

estimates are incomplete since current 

methods are only able to reflect a partial 

accounting of the climate change 

impacts identified by the IPCC 

(discussed more below). Also, domestic 

estimates omit potential impacts on the 

United States (e.g., economic or national 

security impacts) resulting from climate 

change impacts in other countries. The 

global estimates were developed from a 

survey analysis of the peer reviewed 

literature (i.e., meta analysis). U.S. 

estimates, and a consistent set of global 

estimates, were developed from a single 

model and are highly preliminary, 

under evaluation, and likely to be 

revised. The latter set of estimates was 

developed because the peer reviewed 

literature does not currently provide 

regional (i.e., at the U.S. or China level) 

marginal benefits estimates, and it was 

important to have a consistent set of 

regional and global estimates. Ranges of 

estimates are provided to capture some 

of the uncertainties associated with 

modeling climate change impacts. 

The range of estimates is wide due to 

the uncertainties relating to socioeconomic futures, climate 

responsiveness, impacts modeling, as 

well as the choice of discount rate. For 

instance, for 2007 emission reductions 

and a 2% discount rate the global meta 

analysis estimates range from $¥3 to 

$159/tCO2, while the U.S. estimates 

range from $0 to $16/tCO2. For 2007 

emission reductions and a 3% discount 

rate, the global meta-estimates range 

from $¥4 to $106/tCO2, and the U.S. 

estimates range from $0 to $5/tCO2.491

The global meta analysis mean values 

for 2007 emission reductions are $68 

and $40/tCO2 for discount rates of 2% 

and 3%, respectively (in 2006 real 

dollars), while the domestic mean value 

from a single model are $4 and $1/tCO2

for the same discount rates. The 

estimates for future year emission 

changes will be higher as future 

marginal emissions increases are 

expected to produce larger incremental 

damages as physical and economic 

systems become more stressed as the 

magnitude of climate change 

increases.492

TABLE IX.C.2–1—MARGINAL GHG BENEFITS ESTIMATES FOR DISCOUNT RATES OF 2%, 3%, AND 7% AND YEAR OF

EMISSIONS CHANGE IN 2022 

[All values are reported in 2006$/tCO2] 

2% 3% 7% b

Low Central High Low Central High Low Central High 

Meta global .................................. ¥2 105 247 ¥2 62 165 n/a n/a n/a 

FUND global ................................ ¥4 136 1083 ¥4 26 206 ¥2 ¥1 9 

FUND domestic ............................ a 0 7 26 a 0 2 9 a 0 a 0 a 0 

aThese estimates, if explicitly estimated, may be greater than zero, especially in later years. They are currently reported as zero because the 

explicit estimates for an earlier year were zero and were grown at 3% per year. However, we do not anticipate that the explicit estimates for 

these later years would be significantly above zero given the magnitude of the current central estimates for discount rates of 2% and 3% and the 

effect of the high discount rate in the case of 7%. bExcept for illustrative purposes, the marginal benefits estimates in the peer reviewed literature do not use consumption discount rates as high 

as 7%. 

The meta analysis ranges were 

developed from the Tol (2008) meta 

analysis. The meta analysis range only 

includes global estimates generated by 

more recent peer reviewed studies (i.e., 

published after 1995). In addition, the 

ranges only consider regional 

aggregations using simple summation 

and intergenerational consumption 

discount rates of approximately 2% and 

3%.493 Discount rates of 2% and 3% are 

consistent with EPA and OMB guidance 

on intergenerational discount rates 

(EPA, 2000; OMB, 2003).494 The 

estimated distributions of the meta 

global estimates are right skewed with 

long right tails, which is consistent with 

characterizations of the low probability 

high impact damages (see the DRIA for 

the estimated probability density 

functions by discount rate).495 The 

central meta estimates in Table IX.C.2– 

1 are means, and the low and high are 

the 5th and 95th percentiles. Means are 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25095 

496FUND is a spatially and temporally consistent 

framework—across regions of the world (e.g., U.S., 

China), impacts sectors, and time. FUND explicitly 

models impacts sectors in 16 global regions. FUND 

is one of the few models in the world that explicitly 

models global and regional marginal benefits 

estimates. Numerous applications of FUND have 

been published in the peer reviewed literature 

dating back to 1997. See http://www.fnu.zmaw.de/ 

FUND.5679.0.html. 

497 In IPCC reports, equilibrium climate 

sensitivity refers to the equilibrium change in the 

annual mean global surface temperature following 

a doubling of the atmospheric equivalent carbon 

dioxide concentration. The IPCC states that climate 

sensitivity is ‘‘likely’’ to be in the range of 2 °C to 

4.5 °C and described 3 °C as a ‘‘best estimate’’, 

which is the mode (or most likely) value. The IPCC 

goes on to note that climate sensitivity is ‘‘very 

unlikely’’ to be less than 1.5 °C and ‘‘values 

substantially higher than 4.5 °C cannot be 

excluded.’’ IPCC WGI, 2007, Climate Change 2007— 

The Physical Science Basis, Contribution of 

Working Group I to the Fourth Assessment Report 

of the IPCC, http://www.ipcc.ch/. 

498The IMAGE model SRES baseline data was 

used for the A1b, A2, and B2 scenarios (IPCC, 2000. 

Special Report on Emissions Scenarios. A special 

report of Working Group III of the 

Intergovernmental Panel on Climate Change. 

Cambridge University Press, Cambridge). 

499The EPA guidance on intergenerational 

discounting states that ‘‘[e]conomic analyses should 

present a sensitivity analysis of alternative discount 

rates, including discounting at two to three percent 

and seven percent as in the intra-generational case, 

as well as scenarios using rates in the interval onehalf to three percent as prescribed by optimal 

growth models.’’ (EPA, 2000). 

500This number may be updated to be consistent 

with recent EPA regulatory impact analyses that 

have used a value of $6.4 million (in 2006 real 

dollars). 

501 IPCC WGII, 2007. In the IPCC report, ‘‘very 

likely’’ was defined as a greater than 90% 

likelihood based on expert judgment. 

502E.g, Webster et al., 2003; Weitzman, M., 2007. 

http://econweb.fas.harvard.edu/faculty/weitzman/ 

papers/ValStatLifeClimate.pdf. 

503Because some types of potential climate 

change impacts may occur suddenly or begin to 

Continued 

presented because, as a central statistic, 

they better represent the skewed shape 

of these distributions compared to 

medians. 

The consistent domestic and global 

estimates were developed using the 

FUND integrated assessment model (i.e., 

the Climate Framework for Uncertainty, 

Negotiation, and Distribution).496 The 

ranges were generated from sensitivity 

analyses where we varied assumptions 

with respect to climate sensitivity (1.5 

to 6.0 degrees Celsius),497 the socioeconomic and emissions baseline 

scenarios (the FUND default baseline 

and three baselines from the 

Intergovernmental Panel on Climate 

Change (IPCC) Special Report on 

Emissions Scenarios, SRES),498 and the 

consumption discount rates of 

approximately 2%, 3%, and 7%, where 

2% and 3% are consistent with 

intergenerational discounting.499

Furthermore, the model was calibrated 

to the EPA value of a statistical life of 

$7.4 million (in 2006 real dollars).500

The FUND global estimates are the sum 

of the regional estimates within FUND. 

The FUND global and domestic central 

values in Table IX.C.2–1 are weighted 

averages of the FUND estimates from the 

sensitivity analysis (see the DRIA for 

details). The low and high values are the 

low and high estimates across the 

sensitivity runs. 

From Table IX.C.2–1, we see that, in 

terms of the current monetized benefits, 

the domestic marginal benefits are a 

fraction of the global marginal benefits. 

Given uncertainties and omitted 

impacts, it is difficult to estimate the 

actual ratio of total domestic benefits to 

total global benefits. The estimates 

suggest that an emissions reduction will 

have direct benefits for current and 

future U.S. populations and large 

benefits for global populations. The 

long-run and intergenerational 

implications of GHG emissions are 

evident in the difference in results 

across discount rates. In the current 

modeling, there are substantial long-run 

benefits (beyond the next two decades 

to over 100 years) and some near-term 

benefits as well as negative effects (e.g., 

agricultural productivity and heating 

demand). High discount rates give less 

weight to the distant benefits in the net 

present value calculations, and more 

weight to near-term effects. While not 

obvious in Table IX.C.2–1, an additional 

unit of emissions in the higher climate 

sensitivity scenarios, versus the lower 

climate sensitivity scenarios, is 

estimated to have a proportionally larger 

effect on the rest of the world compared 

to the U.S. (see more detailed results in 

DRIA). These points are discussed more 

below. 

3. Discussion of Marginal GHG Benefits 

Estimates 

This section briefly discusses 

important issues relevant to the 

marginal benefits estimates in Table 

IX.C.2–1 (see the DRIA for more 

extensive discussion). The broad range 

of estimates in Table IX.C.2–1 reflects 

some of the uncertainty associated with 

estimating monetized marginal benefits 

of climate change. The meta analysis 

range reflects differences in these 

assumptions as well as differences in 

the modeling of changes in climate and 

impacts considered and how they were 

modeled. EPA considers the meta 

analysis results to be more robust than 

the single model estimates in that the 

meta results reflect uncertainties in both 

models and assumptions. 

The current state-of-the-art for 

estimating benefits is important to 

consider when evaluating policies. 

There are significant partially 

unquantified and omitted impact 

categories not captured in the estimates 

provided above. The IPCC WGII (2007) 

concluded that current estimates are 

‘‘very likely’’ to be underestimated 

because they do not include significant 

impacts that have yet to be 

monetized.501 Current estimates do not 

capture many of the main reasons for 

concern about climate change, including 

nonmarket damages (e.g., species 

existence value and the value of having 

the option for future use), the effects of 

climate variability, risks of potential 

extreme weather (e.g., droughts, heavy 

rains and wind), socially contingent 

effects (such as violent conflict or 

humanitarian crisis), and thresholds (or 

tipping points) associated with species, 

ecosystems, and potential long-term 

catastrophic events (e.g., collapse of the 

West Antarctic Ice Sheet, slowing of the 

Atlantic Ocean Thermohaline 

Circulation). Underestimation is even 

more likely when one considers that the 

current trajectory for GHG emissions is 

higher than typically modeled, which 

when combined with current regional 

population and income trajectories that 

are more asymmetric than typically 

modeled, imply greater climate change 

and vulnerability to climate change. See 

the DRIA for an initial, partial list of 

impacts that are currently not modeled 

in the FUND model and are thus not 

reflected in the FUND estimates. EPA is 

planning to develop a full assessment of 

what is not currently being captured in 

FUND for the final rule. In addition, 

EPA plans to quantify omitted impacts 

and update impacts currently 

represented to the maximum extent 

possible for the final rule. 

The current estimates are also 

deterministic in that they do not 

account for the value people have for 

changes in risk due to changes in the 

likelihood of potential impacts 

associated with reductions in CO2 and 

other GHG emissions (i.e., a risk 

premium). This is an issue that has 

concerned Weitzman and other 

economists.502 We plan to conduct a 

formal uncertainty analysis for the final 

rule to attempt to account for, to the 

extent possible, these and other changes 

in uncertainty. 

The estimates in Table IX.C.2–1 are 

only relevant for incremental policies 

relative to the projected baselines (that 

do not reflect potential future climate 

policies) and there is substantial 

uncertainty associated with the 

estimates themselves both in terms of 

what is being modeled and what is not 

being modeled, with many uncertainties 

outside of observed variability.503 Both 

25096 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

increase at a much faster rate, rather than increasing 

gradually or smoothly, different approaches are 

necessary for quantifying the benefits of ‘‘large’’ 

(non-incremental) versus ‘‘small’’ (incremental) 

reductions in global GHGs. Marginal benefits 

estimates, like those presented above, can be useful 

for estimating benefits for small changes in 

emissions. See the DRIA for additional discussion 

of this point. Note that even small reductions in 

global GHG emissions are expected to reduce 

climate change risks, including catastrophic risks. 

504Recently, the National Highway Traffic Safety 

Administration (NHTSA) issued the final 

Environmental Impact Statement for their proposed 

rulemaking for average fuel economy standards for 

passenger cars and light trucks in which the 

preferred alternative is based upon a domestic 

marginal benefit estimate for carbon dioxide 

reductions. See Average Fuel Economy Standards, 

Passenger Cars and Light Trucks, MY 2011–2015, 

Final Environmental Impact Statement http:// 

www.nhtsa.dot.gov/portal/site/nhtsa/ 

menuitem.43ac99aefa80569eea57529cdba046a0/. 

505OMB (2003), page 15. 

506Nordhaus, W., 2006, ‘‘Paul Samuelson and 

Global Public Goods,’’ in M. Szenberg, L. 

Ramrattan, and A. Gottesman (eds), Samuelsonian 

Economics, Oxford. 

507Both the United Kingdom and the European 

Commission following these economic principles in 

consideration of the global social cost of carbon 

(SCC) for valuing the benefits of GHG emission 

reductions in regulatory impact assessments and 

cost-benefit analyses (Watkiss et al. 2006). 

508Nordhaus, William D. (1995). ‘‘Locational 

Competition and the Environment: Should 

Countries Harmonize Their Environmental 

Policies?’’ in Locational Competition in the World 

Economy, Symposium 1994, ed., Horst Siebert, J. C. 

B. Mohr (Paul Siebeck), Tuebingen, 1995. 

509EPA (U.S. Environmental Protection Agency), 

2000. Guidelines for Preparing Economic Analyses. 

EPA 240–R–00–003. See also OMB (U.S. Office of 

Management and Budget), 2003. Circular A–4. 

September 17, 2003. These documents are the 

guidance used when preparing economic analyses 

for all EPA rulemakings. 510Newell, R. and W. Pizer, 2001. Discounting the 

benefits of climate change mitigation: How much do 

uncertain rates increase valuations? PEW Center on 

Global Climate Change, Washington, DC. Newell, R. 

and W. Pizer, 2003. Discounting the distant future: 

how much do uncertain rates increase valuations? 

Journal of Environmental Economics and 

Management 46:52–71. 

511 Due to differences in atmospheric lifetime and 

radiative forcing, the marginal benefit values of 

non-CO2 GHG reductions and their growth rates 

over time will not be the same as the marginal 

benefits of CO2 emissions reductions (IPCC WGII, 

2007). 

of these points are important for nonmarginal emissions changes and 

estimating total benefits. Also, the 

uncertainties inherent in this kind of 

modeling, including the omissions of 

many important impacts categories, 

present problems for approaches 

attempting to identify an economically 

efficient level of GHG reductions and to 

positive net benefit criteria in general, 

and point to the importance of 

considering factors beyond monetized 

benefits and costs. In uncertain 

situations such as that associated with 

climate, EPA typically recommends that 

analysis consider a range of benefit and 

cost estimates, and the potential 

implications of non-monetized and nonquantified benefits. 

Economic principles suggest that 

global benefits should also be 

considered when evaluating alternative 

GHG reduction policies.504 Typically, 

because the benefits and costs of most 

environmental regulations are 

predominantly domestic, EPA focuses 

on benefits that accrue to the U.S. 

population when quantifying the 

impacts of domestic regulation. 

However, OMB’s guidance for economic 

analysis of federal regulations 

specifically allows for consideration of 

international effects.505 GHGs are global 

and very long-run public goods, and 

economic principles suggest that the full 

costs to society of emissions should be 

considered in order to identify the 

policy that maximizes the net benefits to 

society, i.e., achieves an efficient 

outcome (Nordhaus, 2006).506 As such, 

estimates of global benefits capture 

more of the full value to society than 

domestic estimates and will result in 

higher global net benefits for GHG 

reductions when considered.507

Furthermore, international effects of 

climate change may also affect domestic 

benefits directly and indirectly to the 

extent U.S. citizens value international 

impacts (e.g., for tourism reasons, 

concerns for the existence of 

ecosystems, and/or concern for others); 

U.S. international interests are affected 

(e.g., risks to U.S. national security, or 

the U.S. economy from potential 

disruptions in other nations); and/or 

domestic mitigation decisions affect the 

level of mitigation and emissions 

changes in general in other countries 

(i.e., the benefits realized in the U.S. 

will depend on emissions changes in 

the U.S. and internationally). The 

economics literature also suggests that 

policies based on direct domestic 

benefits will result in little appreciable 

reduction in global GHGs (e.g., 

Nordhaus, 1995).508 While these 

marginal benefits estimates are not 

comprehensive or economically 

optimal, the global estimates in Table 

IX.C.2–1 internalize a larger portion of 

the global and intergenerational 

externalities of reducing a unit of 

emissions. 

A key challenge facing EPA is the 

appropriate discount rate over the 

longer timeframe relevant for GHGs. 

With the benefits of GHG emissions 

reductions distributed over a very long 

time horizon, benefit and cost 

estimations are likely to be very 

sensitive to the discount rate. When 

considering climate change investments, 

they should be compared to similar 

alternative investments (via the 

discount rate). Changes in GHG 

emissions—both increases and 

reductions—are essentially long-run 

investments in changes in climate and 

the potential impacts from climate 

change, which includes the potential for 

significant impacts from climate change, 

where the exact timing and magnitude 

of these impacts are unknown. 

When there are important benefits or 

costs that affect multiple generations of 

the population, EPA and OMB allow for 

low but positive discount rates (e.g., 

0.5–3% noted by U.S. EPA, 1–3% by 

OMB).509 In this multi-generation 

context, the three percent discount rate 

is consistent with observed interest rates 

from long-term investments available to 

current generations (net of risk 

premiums) as well as current estimates 

of the impacts of climate change that 

reflect potential impacts on consumers. 

In addition, rates of three percent or 

lower are consistent with long-run 

uncertainty in economic growth and 

interest rates, considerations of issues 

associated with the transfer of wealth 

between generations, and the risk of 

high impact climate damages. Given the 

uncertain environment, analysis could 

also consider evaluating uncertainty in 

the discount rate (e.g., Newell and Pizer, 

2001, 2003).510

For the final rulemaking, we will be 

developing and updating the FUND 

model as best as possible based on the 

latest research and peer reviewing the 

estimates. To improve upon our 

estimates, we hope to evaluate several 

factors not currently captured in the 

proposed estimates due to time 

constraints. For example, we will 

quantify additional impact categories as 

is possible and provide a qualitative 

evaluation of the implications of what is 

not monetized. We also plan to conduct 

an uncertainty analysis, consider 

complementary bottom-up analyses, and 

develop estimates of the marginal 

benefits associated with non-CO2 GHGs 

relevant to the rule (e.g., CH4, N2O, and 

HFC–134a).511

EPA solicits comment on the 

appropriateness of using U.S. and global 

values in quantifying the benefits of 

GHG reductions and the appropriate 

application of benefits estimates given 

the state of the art and overall 

uncertainties. We also seek comment on 

our estimates of the global and U.S. 

marginal benefits of GHG emissions 

reductions that EPA has developed, 

including the scientific and economic 

foundations, the methods employed in 

developing the estimates, the discount 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25097 

512EPA notes, however, that the Ninth Circuit 

recently rejected an approach of assigning no 

monetized value to greenhouse gas reductions 

resulting from vehicular fuel economy. Center for 

Biodiversity v. NHTSA, F. 3d, (9th Cir. 2007). 

513U.S. Environmental Protection Agency. July 

2007. Regulatory Impact Analysis of the Proposed 

Revisions to the National Ambient Air Quality 

Standards for Ground-Level Ozone. Prepared by: 

Office of Air and Radiation. EPA–452/R–07–008. 

514U.S. Environmental Protection Agency. 

October 2006. Final Regulatory Impact Analysis 

(RIA) for the Proposed National Ambient Air 

Quality Standards for Particulate Matter. Prepared 

by: Office of Air and Radiation. 

rates considered, current and proposed 

future consideration of uncertainty in 

the estimates, marginal benefits 

estimates for non-CO2 GHG emissions 

reductions, and potential opportunities 

for improving the estimates. We are also 

interested in comments on methods for 

quantifying benefits for non-incremental 

reductions in global GHG emissions. 

Because the literature on SCC and our 

understanding of that literature 

continues to evolve, EPA will continue 

to assess the best available information 

on the social cost of carbon and climate 

benefits, and may adjust its approaches 

to quantifying and presenting 

information on these areas in future 

rulemakings. 

4. Total Monetized GHG Benefits 

Estimates 

As described in Section VI.F, 

annualized equivalent GHG emissions 

reductions associated with the RFS2 

proposal in 2022 would be 160 million 

metric tons of CO2 equivalent 

(MMTCO2eq) with a 2% discount rate, 

and 155 and 136 MMCO2eq with 

discount rates of 3% and 7%, 

respectively. This section provides the 

monetized total GHG benefits estimates 

associated with the proposal in 2022. As 

discussed above in Section IX.C.3, these 

estimates do not include significant 

impacts that have yet to be monetized. 

Total monetized benefits in 2022 are 

calculated by multiplying the marginal 

benefits per metric ton of CO2 in that 

year by the annualized equivalent 

emissions reductions. For the final 

rulemaking, we plan to separate the 

emissions reductions by gas and use 

CO2 and non-CO2 marginal benefits 

estimates. Non-CO2 GHGs have different 

climate and atmospheric implications 

and therefore different marginal climate 

impacts. 

Table IX.C.4–1 provides the estimated 

monetized GHG benefits of the proposal 

for 2022. The large range of values in 

the Table reflects some of the 

uncertainty captured in the range of 

monetized marginal benefits estimates 

presented in Table IX.C.2–1.512 All 

values in this section are presented in 

2006 real dollars. 

TABLE IX.C.4–1—MONETIZED GHG BENEFITS OF THE PROPOSED RULE IN 2022 

[Billion 2006$] 

Marginal benefit 2% 3% 7% 

Meta global ..................................................... Low ................................................................. ¥$0.3 ¥$0.3 n/a 

Central ............................................................ 16.8 9.6 n/a 

High ................................................................ 39.4 25.5 n/a 

FUND global ................................................... Low ................................................................. ¥0.6 ¥0.6 ¥0.3 

Central ............................................................ 21.7 4.0 ¥0.1 

High ................................................................ 172.8 31.9 1.2 

FUND domestic ............................................... Low ................................................................. 0.0 0.0 0.0 

Central ............................................................ 1.1 0.3 0.0 

High ................................................................ 4.1 1.4 0.0 

D. Co-pollutant Health and 

Environmental Impacts 

This section describes EPA’s analysis 

of the co-pollutant health and 

environmental impacts that can be 

expected to occur as a result of this 

renewable fuels proposal throughout the 

period from initial implementation 

through 2030. GHG emissions are 

predominantly the byproduct of fossil 

fuel combustion processes that also 

produce criteria and hazardous air 

pollutants. The fuels that are subject to 

the proposed standard are also 

significant sources of mobile source air 

pollution such as direct PM, NOX, VOCs 

and air toxics. The proposed standard 

would affect exhaust and evaporative 

emissions of these pollutants from 

vehicles and equipment. They would 

also affect emissions from upstream 

sources such as fuel production, storage, 

and distribution and agricultural 

emissions. Any decrease or increase in 

ambient ozone, PM2.5, and air toxics 

associated with the proposal would 

impact human health in the form of 

avoided or incurred premature deaths 

and other serious human health effects, 

as well as other important public health 

and welfare effects. 

As can be seen in Section II.B, we 

estimate that the proposal would lead to 

both increased and decreased criteria 

and air toxic pollutant emissions. 

Making predictions about human health 

and welfare impacts based solely on 

emissions changes, however, is 

extremely difficult. Full-scale 

photochemical modeling is necessary to 

provide the needed spatial and temporal 

detail to more completely and 

accurately estimate the changes in 

ambient levels of these pollutants. EPA 

typically quantifies and monetizes the 

PM- and ozone-related health and 

environmental impacts in its regulatory 

impact analyses (RIAs) when possible. 

However, we were unable to do so in 

time for this proposal. EPA attempts to 

make emissions and air quality 

modeling decisions early in the 

analytical process so that we can 

complete the photochemical air quality 

modeling and use that data to inform 

the health and environmental impacts 

analysis. Resource and time constraints 

precluded the Agency from completing 

this work in time for the proposal. EPA 

will, however, provide a complete 

characterization of the health and 

environmental impacts, both in terms of 

incidence and valuation, for the final 

rulemaking. 

This section explains what PM- and 

ozone-related health and environmental 

impacts EPA will quantify and monetize 

in the analysis for the final rules. EPA 

will base its analysis on peer-reviewed 

studies of air quality and health and 

welfare effects and peer-reviewed 

studies of the monetary values of public 

health and welfare improvements, and 

will be consistent with benefits analyses 

performed for the recent analysis of the 

proposed Ozone NAAQS and the final 

PM NAAQS analysis.513 514 These 

methods will be described in detail in 

the DRIA prepared for the final rule. 

Though EPA is characterizing the 

changes in emissions associated with 

toxic pollutants, we will not be able to 

25098 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

515U.S. Environmental Protection Agency. 

February 2007. Control of Hazardous Air Pollutants 

from Mobile Sources: Final Regulatory Impact 

Analysis. Office of Air and Radiation. Office of 

Transportation and Air Quality. EPA420–R–07–002. 

516 Information on BenMAP, including 

downloads of the software, can be found at http:// 

www.epa.gov/ttn/ecas/benmodels.html. 

quantify or monetize the human health 

effects associated with air toxic 

pollutants for either the proposal or the 

final rule analyses. This is primarily 

because available tools and methods to 

assess air toxics risk from mobile 

sources at the national scale are not 

adequate for extrapolation to benefits 

assessment. In addition to inherent 

limitations in the tools for national-scale 

modeling of air quality and exposure, 

there is a lack of epidemiology data for 

air toxics in the general population. For 

a more comprehensive discussion of 

these limitations, please refer to the 

final Mobile Source Air Toxics rule.515

Please refer to Section VII for more 

information about the air toxics 

emissions impacts associated with the 

proposed standard. 

1. Human Health and Environmental 

Impacts 

To model the ozone and PM air 

quality benefits of the final rules, EPA 

will use the Community Multiscale Air 

Quality (CMAQ) model (see Section 

VII.D.2 for a description of the CMAQ 

model). The modeled ambient air 

quality data will serve as an input to the 

Environmental Benefits Mapping and 

Analysis Program (BenMAP).516

BenMAP is a computer program 

developed by EPA that integrates a 

number of the modeling elements used 

in previous DRIAs (e.g., interpolation 

functions, population projections, 

health impact functions, valuation 

functions, analysis and pooling 

methods) to translate modeled air 

concentration estimates into health 

effects incidence estimates and 

monetized benefits estimates. 

Table IX.D.1–1 lists the co-pollutant 

health effect exposure-response 

functions (PM2.5 and ozone) we will use 

to quantify the co-pollutant incidence 

impacts associated with the proposal. 

TABLE IX.D.1–1—HEALTH IMPACT FUNCTIONS USED IN BENMAP TO ESTIMATE IMPACTS OF PM2.5 AND OZONE

REDUCTIONS

Endpoint Pollutant Study Study population 

Premature Mortality: 

Premature mortality—daily time series .......... O3 Multi-city ................................................................

Bell et al. (2004)—Non-accidental ........................

All ages. 

Huang et al. (2005)—Cardiopulmonary.

Schwartz (2005)—Non-accidental.

Meta-analyses: 

Bell et al. (2005)—All cause.

Ito et al. (2005)—Non-accidental.

Levy et al. (2005)—All cause.

Premature mortality—cohort study, all-cause ....... PM2.5 Pope et al. (2002) .................................................

Laden et al. (2006) ...............................................

>29 years. 

>25 years. 

Premature mortality, total exposures .................... PM2.5 Expert Elicitation (IEc, 2006) ................................ >24 years. 

Premature mortality—all-cause ............................. PM2.5 Woodruff et al. (1997) ........................................... Infant (<1 year). 

Chronic Illness: 

Chronic Bronchitis .......................................... PM2.5 Abbey et al. (1995) ............................................... >26 years. 

Nonfatal heart attacks .................................... PM2.5 Peters et al. (2001) ............................................... Adults (>18 years). 

Hospital Admissions: 

Respiratory ..................................................... O3 Pooled estimate .................................................... >64 years. 

Schwartz (1995)—ICD 460–519 (all resp).

Schwartz (1994a; 1994b)—ICD 480–486 

(pneumonia).

Moolgavkar et al. (1997)—ICD 480–487 

(pneumonia).

Schwartz (1994b)—ICD 491–492, 494–496 

(COPD).

Moolgavkar et al. (1997)—ICD 490–496 

(COPD).

Burnett et al. (2001) .............................................. <2 years. 

PM2.5 Pooled estimate .................................................... >64 years. 

Moolgavkar (2003)—ICD 490–496 (COPD).

Ito (2003)—ICD 490–496 (COPD).

PM2.5 Moolgavkar (2000)—ICD 490–496 (COPD) ......... 20–64 years. 

PM2.5 Ito (2003)—ICD 480–486 (pneumonia) ................ >64 years. 

PM2.5 Sheppard (2003)—ICD 493 (asthma) ................... <65 years. 

Cardiovascular ............................................... PM2.5 Pooled estimate .................................................... >64 years. 

Moolgavkar (2003)—ICD 390–429 (all Cardiovascular).

Ito (2003)—ICD 410–414, 427–428 

(ischemic heart disease, dysrhythmia, 

heart failure).

PM2.5 Moolgavkar (2000)—ICD 390–429 (all Cardiovascular).20–64 years. 

Asthma-related ER visits ............................... O3 Pooled estimate .................................................... 5–34 years. 

Jaffe et al. (2003) .......................................... All ages. 

Peel et al. (2005) ........................................... All ages. 

Wilson et al. (2005).

PM2.5 Norris et al. (1999) ................................................ 0–18 years. 

Other Health Endpoints: 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25099 

TABLE IX.D.1–1—HEALTH IMPACT FUNCTIONS USED IN BENMAP TO ESTIMATE IMPACTS OF PM2.5 AND OZONE

REDUCTIONS—Continued 

Endpoint Pollutant Study Study population 

Acute bronchitis ............................................. PM2.5 Dockery et al. (1996) ............................................ 8–12 years. 

Upper respiratory symptoms .......................... PM2.5 Pope et al. (1991) ................................................. Asthmatics, 9–11 years. 

Lower respiratory symptoms .......................... PM2.5 Schwartz and Neas (2000) ................................... 7–14 years. 

Asthma exacerbations ................................... PM2.5 Pooled estimate .................................................... 6–18 years. 

Ostro et al. (2001) (cough, wheeze and 

shortness of breath).

Vedal et al. (1998) (cough).

Work loss days .............................................. PM2.5 Ostro (1987) .......................................................... 18–65 years. 

School absence days ..................................... O3 Pooled estimate .................................................... 5–17 years. 

Gilliland et al. (2001).

Chen et al. (2000).

Minor Restricted Activity Days (MRADs) ....... O3 Ostro and Rothschild (1989) ................................. 18–65 years. 

PM2.5 Ostro and Rothschild (1989) ................................. 18–65 years. 

2. Monetized Impacts 

Table IX.D.2–1 presents the monetary 

values we will apply to changes in the 

incidence of health and welfare effects 

associated with the RFS2 standard. 

TABLE IX.D.2–1—VALUATION METRICS USED IN BENMAP TO ESTIMATE MONETARY BENEFITS

Endpoint Valuation method Valuation 

(2000$) 

Premature mortality ................................. Assumed Mean VSL ................................................................................................ $5,500,000 

Chronic Illness 

Chronic Bronchitis ............................ WTP: Average Severity ........................................................................................... 340,482 

Myocardial Infarctions, Nonfatal ....... Medical Costs Over 5 Years. Varies by age and discount rate. Russell (1998) .... ..............................

Medical Costs Over 5 Years. Varies by age and discount rate. Wittels (1990) ..... ..............................

Hospital Admissions 

Respiratory, Age 65+ ....................... COI: Medical Costs + Wage Lost ............................................................................ 18,353 

Respiratory, Ages 0–2 ..................... COI: Medical Costs .................................................................................................. 7,741 

Chronic Lung Disease (less Asthma).COI: Medical Costs + Wage Lost ............................................................................ 12,378 

Pneumonia ....................................... COI: Medical Costs + Wage Lost ............................................................................ 14,693 

Asthma ............................................. COI: Medical Costs + Wage Lost ............................................................................ 6,634 

Cardiovascular ................................. COI: Medical Costs + Wage Lost (20–64) .............................................................. 22,778 

COI: Medical Costs + Wage Lost (65–99) .............................................................. 21,191 

ER Visits, Asthma ................................... COI: Smith et al. (1997) .......................................................................................... 312 

COI: Standford et al. (1999) .................................................................................... 261 

Other Health Endpoints 

Acute Bronchitis ............................... WTP: 6 Day Illness, CV Studies ............................................................................. 356 

Upper Respiratory Symptoms .......... WTP: 1 Day, CV Studies ......................................................................................... 25 

Lower Respiratory Symptoms .......... WTP: 1 Day, CV Studies ......................................................................................... 16 

Asthma Exacerbation ....................... WTP: Bad Asthma Day, Rowe and Chestnut (1986) .............................................. 43 

Work Loss Days ............................... Median Daily Wage, County-Specific ...................................................................... ..............................

Minor Restricted Activity Days ......... WTP: 1 Day, CV Studies ......................................................................................... 51 

School Absence Days ...................... Median Daily Wage, Women 25+ ........................................................................... 75 

Worker Productivity .......................... Median Daily Wage, Outdoor Workers, County-Specific, Crocker and Horst 

(1981).

..............................

Environmental Endpoints Recreational 

Visibility.

WTP: 86 Class I Areas ............................................................................................ ..............................

Source: Dollar amounts for each valuation method were extracted from BenMAP version 2.4.5. 

3. Other Unquantified Health and 

Environmental Impacts 

In addition to the co-pollutant health 

and environmental impacts we will 

quantify for the analysis of the RFS2 

standard, there are a number of other 

health and human welfare endpoints 

that we will not be able to quantify 

because of current limitations in the 

methods or available data. These 

impacts are associated with emissions of 

air toxics (including benzene, 1,3- 

butadiene, formaldehyde, acetaldehyde, 

acrolein, and ethanol), ambient ozone, 

and ambient PM2.5 exposures. For 

example, we have not quantified a 

number of known or suspected health 

effects linked with ozone and PM for 

which appropriate health impact 

functions are not available or which do 

not provide easily interpretable 

outcomes (i.e., changes in heart rate 

variability). Additionally, we are 

currently unable to quantify a number of 

known welfare effects, including 

reduced acid and particulate deposition 

damage to cultural monuments and 

other materials, and environmental 

benefits due to reductions of impacts of 

eutrophication in coastal areas. For air 

toxics, the available tools and methods 

to assess risk from mobile sources at the 

national scale are not adequate for 

extrapolation to benefits assessment. In 

addition to inherent limitations in the 

25100 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

517Science Advisory Board. 2001. NATA— 

Evaluating the National-Scale Air Toxics 

Assessment for 1996—an SAB Advisory. http:// 

www.epa.gov/ttn/atw/sab/sabrev.html. 

518U.S. EPA. 2007. Control of Hazardous Air 

Pollutants From Mobile Sources—Regulatory 

Impact Analysis. Assessment and Standards 

Division. Office of Transportation and Air Quality. 

EPA420R–07–002. February. 

tools for national-scale modeling of air 

toxics and exposure, there is a lack of 

epidemiology data for air toxics in the 

general population. Table IX.D.3–1 lists 

these unquantified health and 

environmental impacts. 

TABLE IX.D.3–1—UNQUANTIFIED AND

NON-MONETIZED POTENTIAL EFFECTS

Pollutant/Effects Effects not included in analysis—changes in: 

Ozone Health a Chronic respiratory damage. 

Premature aging of the 

lungs. 

Non-asthma respiratory 

emergency room visits. 

Exposure to UVb (±) d. 

Ozone Welfare Yields for: 

—commercial forests. 

—some fruits and vegetables. 

—non-commercial crops. 

Damage to urban ornamental plants. 

Impacts on recreational demand from damaged forest aesthetics. 

Ecosystem functions. 

Exposure to UVb (±). 

PM Health b .... Premature mortality—short 

term exposures.c

Low birth weight. 

Pulmonary function. 

Chronic respiratory diseases 

other than chronic bronchitis. 

Non-asthma respiratory 

emergency room visits. 

Exposure to UVb (±). 

PM Welfare .... Residential and recreational 

visibility in non-Class I 

areas. 

Soiling and materials damage. 

Damage to ecosystem functions. 

Exposure to UVb (±). 

Nitrogen and 

Sulfate Deposition Welfare.

Commercial forests due to 

acidic sulfate and nitrate 

deposition. 

Commercial freshwater fishing due to acidic deposition. 

Recreation in terrestrial ecosystems due to acidic deposition. 

Existence values for currently healthy ecosystems. 

Commercial fishing, agriculture, and forests due to 

nitrogen deposition. 

Recreation in estuarine ecosystems due to nitrogen 

deposition. 

Ecosystem functions. 

Passive fertilization. 

CO Health ...... Behavioral effects. 

Hydrocarbon 

(HC)/Toxics 

Health e.

Cancer (benzene, 1,3-butadiene, formaldehyde, acetaldehyde, ethanol). 

Anemia (benzene). 

TABLE IX.D.3–1—UNQUANTIFIED AND

NON-MONETIZED POTENTIAL EFFECTS—Continued 

Pollutant/Effects Effects not included in analysis—changes in: 

Disruption of production of 

blood components (benzene). 

Reduction in the number of 

blood platelets (benzene). 

Excessive bone marrow formation (benzene). 

Depression of lymphocyte 

counts (benzene). 

Reproductive and developmental effects (1,3-butadiene, ethanol). 

Irritation of eyes and mucus 

membranes (formaldehyde). 

Respiratory irritation (formaldehyde). 

Asthma attacks in 

asthmatics (formaldehyde). 

Asthma-like symptoms in 

non-asthmatics (formaldehyde). 

Irritation of the eyes, skin, 

and respiratory tract (acetaldehyde). 

Upper respiratory tract irritation and congestion (acrolein). 

HC/Toxics 

Welfare f.

Direct toxic effects to animals. 

Bioaccumulation in the food 

chain. 

Damage to ecosystem function. 

Odor. 

a In addition to primary economic endpoints, 

there are a number of biological responses 

that have been associated with ozone health 

effects including increased airway responsiveness to stimuli, inflammation in the lung, acute 

inflammation and respiratory cell damage, and 

increased susceptibility to respiratory infection. 

The public health impact of these biological responses may be partly represented by our 

quantified endpoints. b In addition to primary economic endpoints, 

there are a number of biological responses 

that have been associated with PM health effects including morphological changes and altered host defense mechanisms. The public 

health impact of these biological responses 

may be partly represented by our quantified 

endpoints. cWhile some of the effects of short-term exposures are likely to be captured in the estimates, there may be premature mortality due 

to short-term exposure to PM not captured in 

the cohort studies used in this analysis. However, the PM mortality results derived from the 

expert elicitation do take into account premature mortality effects of short term exposures. d May result in benefits or disbenefits. 

e Many of the key hydrocarbons related to 

this rule are also hazardous air pollutants listed in the Clean Air Act. Please refer to Section VII.E.4 for additional information on the 

health effects of air toxics. fPlease refer to Section VII.E for additional 

information on the welfare effects of air toxics. 

While there will be impacts 

associated with air toxic pollutant 

emission changes that result from the 

RFS2 standard, we will not attempt to 

monetize those impacts. This is 

primarily because currently available 

tools and methods to assess air toxics 

risk from mobile sources at the national 

scale are not adequate for extrapolation 

to incidence estimations or benefits 

assessment. The best suite of tools and 

methods currently available for 

assessment at the national scale are 

those used in the National-Scale Air 

Toxics Assessment (NATA). The EPA 

Science Advisory Board specifically 

commented in their review of the 1996 

NATA that these tools were not yet 

ready for use in a national-scale benefits 

analysis, because they did not consider 

the full distribution of exposure and 

risk, or address sub-chronic health 

effects.517 While EPA has since 

improved the tools, there remain critical 

limitations for estimating incidence and 

assessing benefits of reducing mobile 

source air toxics. EPA continues to work 

to address these limitations; however, 

we do not anticipate having methods 

and tools available for national-scale 

application in time for the analysis of 

the final rules. Please refer to the final 

Mobile Source Air Toxics Rule RIA for 

more discussion.518

E. Economy-Wide Impacts 

It is anticipated that this proposed 

rulemaking will have impacts on the 

U.S. economy that extend beyond the 

two sectors most directly affected—the 

transportation and agriculture sectors. 

Consider how the proposed rulemaking 

will affect the overall U.S. economy. By 

requiring 36 billion gallons of renewable 

transportation fuels in the U.S. 

transportation sector by 2022, it is 

anticipated that the cost of motor 

vehicle fuels will increase. This cost 

increase will impact all sectors of the 

economy that use motor vehicles fuels, 

as intermediate inputs to production. 

For example, manufacturing firms will 

see an increase in their shipping costs. 

Households will also be impacted as 

consumers of these goods, and directly 

as consumers of motor vehicle fuels. 

Additionally, it is anticipated that the 

production of renewable fuels will 

increase the demand for U.S. farm 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25101 

519U.S. Department of Agriculture, National 

Agricultural Statistics Service, ‘‘Acreage’’, 2008, 

available online at: http:// 

usda.mannlib.cornell.edu/usda/current/Acre/Acre06–30–2008.pdf. 

520Committee on Water Implications of Biofuels 

Production in the United States, National Research 

Council, 2008, Water implications of biofuels 

production in the United States, The National 

Academies Press, Washington, DC, 88 p. 

521U.S. Environmental Protection Agency, EPA 

Science Advisory Board, Hypoxia in the northern 

Gulf of Mexico, EPA–SAB–08–003, 275 p, available 

online at: http://yosemite.epa.gov/sab/ 

sabproduct.nsf/ 

C3D2F27094E03F90852573B800601D93/$File/EPA– 

SAB–08–003complete.unsigned.pdf. 

products, and increase farm incomes. 

This will have ripple effects for sectors 

that supply inputs to the U.S. farm 

sector (e.g. tractors), and sectors that 

demand outputs from the farm sector. 

The sum of all of these impacts will 

affect the total levels of output and 

consumption in the U.S. economy. 

Because multiple markets beyond the 

transportation sector will be affected by 

the proposed rulemaking, a general 

equilibrium analysis is required to 

provide a more accurate picture of the 

social cost of the policy than a partial 

equilibrium analysis. (A partial 

equilibrium analysis looks at the 

impacts in one market of the economy 

but does not attempt to capture the full 

interaction of a policy change in all 

markets simultaneously, as a general 

equilibrium model does). 

In order to estimate the impacts of the 

RFS2 rule on U.S. gross domestic 

product (GDP) and consumption, EPA 

intends to use an economy-wide, 

computable general equilibrium (CGE) 

model between proposal and the final 

rule. This model will use detailed fuel 

sector cost estimates provided in 

Section VIII as inputs to determine the 

economy-wide impacts of the 

rulemaking. The economy-wide model 

to be utilized for this analysis is the 

Intertemporal General Equilibrium 

Model (IGEM). IGEM is a model of the 

U.S. economy with an emphasis on the 

energy and environmental aspects. It is 

a dynamic model, which depicts growth 

of the economy due to capital 

accumulation, technical change and 

population change. It is a detailed 

multi-sector model covering thirty-five 

industries of the U.S. economy. It also 

depicts changes in consumption 

patterns due to demographic changes, 

price and income effects. The 

substitution possibilities for both 

producers and consumers in IGEM are 

driven by model parameters that are 

based on observed market behavior 

revealed over the past forty to fifty 

years. EPA seeks comment on the 

modeling approach to be utilized to 

estimate the economy-wide impacts of 

the RFS2 proposal. 

An additional issue that arises is how 

biofuel subsidies are considered from an 

economy-wide perspective. The 

Renewable Fuels Standard, by 

encouraging the use of biofuels, will 

result in an expansion of subsidy 

payments by the U.S. For example, each 

gallon of corn-based ethanol sold in the 

U.S. qualifies for a $0.45/gallon subsidy. 

One assumption that could be made is 

that biofuel subsidies, which are a loss 

in revenue to the U.S. government, are 

offset by an increase in taxes by the U.S. 

In this case, the Renewable Fuels 

Standard program becomes revenue 

neutral. If taxes are raised to offset the 

revenue loss from the subsidies, the 

taxes could have a distortionary impact 

on the economy. For example, if taxes 

are raised on labor and capital, then 

there will less output. To account for 

the potential distortionary impacts of 

increased taxes, as a rule of thumb, it is 

sometimes assumed that for each dollar 

of tax revenue raised, there is a $0.25 

loss in output in the economy. We 

intend to consider the impact of the 

expansion of biofuel subsidies from the 

RFS2 in the context of the economywide modeling. 

X. Impacts on Water 

A. Background 

As the production and price of corn 

and other biofuel feedstocks increase, 

there may be substantial impacts to both 

water quality and water quantity. To 

analyze the potential water-related 

impacts, EPA focused on agricultural 

corn production for several reasons. 

Corn acres have increased dramatically, 

20% in 2007. Although corn acres 

declined seven percent in 2008, total 

corn acres remained the second highest 

since 1946.519 Corn has the highest 

fertilizer and pesticide use per acre and 

accounts for the largest share of nitrogen 

fertilizer use among all crops.520 Corn 

generally utilizes only 40 to 60% of the 

applied nitrogen fertilizer. The 

remaining nitrogen is available to leave 

the field and runoff to surface waters, 

leach into ground water, or volatilize to 

the air where it can return to water 

through depositional processes. 

There are three major pathways for 

contaminants to reach water from 

agricultural lands: run off from the 

land’s surface, subsurface tile drains, or 

leaching to ground water. A variety of 

management factors influence the 

potential for contaminants such as 

fertilizers, sediment, and pesticides to 

reach water from agricultural lands. 

These factors include nutrient and 

pesticide application rates and 

application methods, use of 

conservation practices and crop 

rotations by farmers, and acreage and 

intensity of tile drained lands. 

Historically, corn has been grown in 

rotation with other crops, especially 

soybeans. As corn prices increase 

relative to prices for other crops, more 

farmers are choosing to grow corn every 

year (continuous corn). Continuous corn 

production results in significantly 

greater nitrogen losses annually than a 

corn-soybean rotation and lower yields 

per acre. In response, farmers may add 

higher rates of nitrogen fertilizer to try 

to match yields of corn grown in 

rotation. Growing continuous corn also 

increases the viability of pests such as 

corn rootworm. Farmers may increase 

use of pesticides to control these pests. 

As corn acres increase, use of the 

common herbicides like atrazine and 

glyphosate (e.g. Roundup) may also 

increase. 

High corn prices may encourage 

farmers to grow corn on lands that are 

marginal for row production such as hay 

land or pasture. Typically, agricultural 

producers apply far less fertilizer and 

pesticide on pasture land than land in 

row crops. Corn yield on these marginal 

lands will be lower and may require 

higher fertilizer rates. However since 

nitrogen fertilizer prices are tied to oil 

prices, fertilizer costs have increased 

significantly recently. It is unclear how 

agricultural producers have responded 

to these increases in both corn and 

fertilizer prices. EPA solicits comments 

on the impact of corn and fertilizer 

prices on nitrogen fertilizer use. 

Tile drainage is another important 

factor in determining the losses of 

fertilizer from cropland. Tile drainage 

consists of subsurface tiles or pipes that 

move water from wet soils to surface 

waters quickly so crops can be planted. 

Tile drainage has transformed large 

expanses of historic wetland soils into 

productive agriculture lands. However, 

the tile drains also move fertilizers and 

pesticides more quickly to surface 

waters without any of the attenuation 

that would occur if these contaminants 

moved through soils or wetlands. The 

highest proportion of tile drainage 

occurs in the Upper Mississippi and the 

Ohio-Tennessee River basins.521

The increase in corn production and 

prices may also have significant impacts 

on voluntary conservation programs 

funded by the U.S. Department of 

Agriculture (USDA) that are important 

to protect water quality. As land values 

increase due to higher crop prices, 

USDA payments may not keep up with 

the need for farmers and tenant farmers, 

to make an adequate return. For 

example, farmland in Iowa increased an 

25102 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

522Louisiana Universities Marine Consortium, 

2008, ‘Dead zone’ again rivals record size, available 

online at: http://www.gulfhypoxia.net/research/ 

shelfwidecruises/2008/PressRelease08.pdf. 

523Mississippi River/Gulf of Mexico Watershed 

Nutrient Task Force, 2008, Gulf hypoxia action plan 

2008 for reducing, mitigating, and controlling 

hypoxia in the northern Gulf of Mexico and 

improving water quality in the Mississippi River 

basin, 61 p., Washington, DC, available online at: 

http://www.epa.gov/msbasin/actionplan.htm. 

524Alexander, R.B., Smith, R.A., Schwarz, G.E., 

Boyer, E.W., Nolan, J.V., and Brakebill, J.W., 2008, 

Differences in phosphorus and nitrogen delivery to 

the Gulf of Mexico from the Mississippi River basin, 

Environmental Science and Technology, v. 42, no. 

3, p. 822–830, available online at: http:// 

pubs.acs.org/cgi-bin/abstract.cgi/esthag/2008/42/ 

i03/abs/es0716103.html. 

525 Donner, S. D. and Kucharik, C. J., 2008, Cornbased ethanol production compromises goal of 

reducing nitrogen export by the Mississippi River, 

PNAS, v. 105, no. 11, p. 4513–4518, available 

online at: http://www.pnas.org/content/105/11/ 

4513.full. 

526U.S. EPA, supra note 4. 

average of 18% in 2007 from 2006 

prices. 

Both land retirement programs like 

the Conservation Reserve Program (CRP) 

and working land programs like the 

Environmental Quality Incentives 

Program (EQIP) can be affected. Under 

CRP, USDA contracts with farmers to 

take land out of agricultural production 

and plant grasses or trees. Generally 

farmers put land into CRP because it is 

not as productive and has other 

characteristics that make the cropland 

more environmentally sensitive, such as 

high erosion rates. CRP provides 

valuable environmental benefits both for 

water quality and for wildlife habitat. 

Midwestern states, where much of U.S. 

corn is grown, tend to have lower CRP 

reenrollment rates than the national 

average. Under EQIP, USDA makes costshare payments to farmers to implement 

conservation practices. Some of the 

most cost-effective practices include: 

Riparian buffers; crop rotation; 

appropriate rate, timing, and method of 

fertilizer application; cover crops; and, 

on tile-drained lands, treatment 

wetlands and controlled drainage. 

Producers may be less willing to 

participate and require higher payments 

to offset perceived loss of profits 

through implementation of conservation 

practices. 

1. Ecological Impacts 

Nitrogen and phosphorus enrichment 

due to human activities is one of the 

leading problems facing our nation’s 

lakes, reservoirs, and estuaries. Nutrient 

enrichment also has negative impacts on 

aquatic life in streams; adverse health 

effects on humans and domestic 

animals; and impairs aesthetic and 

recreational use. Excess nutrients can 

lead to excessive growth of algae in 

rivers and streams, and aquatic plants in 

all waters. For example, declines in 

invertebrate community structure have 

been correlated directly with increases 

in phosphorus concentration. High 

concentrations of nitrogen in the form of 

ammonia are known to be toxic to 

aquatic animals. Excessive levels of 

algae have also been shown to be 

damaging to invertebrates. Finally, fish 

and invertebrates will experience 

growth problems and can even die if 

either oxygen is depleted or pH 

increases are severe; both of these 

conditions are symptomatic of 

eutrophication. As a biologic system 

becomes more enriched by nutrients, 

different species of algae may spread 

and species composition can shift. 

Nutrient pollution is widespread. The 

most widely known examples of 

significant nutrient impacts include the 

Gulf of Mexico and the Chesapeake Bay. 

There are also known impacts in over 80 

estuaries/bays, and thousands of rivers, 

streams, and lakes. Waterbodies in 

virtually every state and territory in the 

U.S. are impacted by nutrient-related 

degradation. Reducing nutrient 

pollution is a priority for EPA. The 

combustion of transportation fuels 

results in significant loadings of 

nitrogen from air deposition to 

waterbodies around the country, 

including the Chesapeake Bay, Long 

Island Sound, and Lake Tahoe. 

2. Gulf of Mexico 

Production of corn for ethanol may 

exacerbate existing serious water quality 

problems in the Gulf of Mexico. 

Nitrogen fertilizer applications to corn 

are already the major source of total 

nitrogen loadings to the Mississippi 

River. A large area of low oxygen, or 

hypoxia, forms in the Gulf of Mexico 

every year, often called the ‘‘dead 

zone.’’ The primary cause of the 

hypoxia is excess nutrients (nitrogen 

and phosphorus) from the Upper 

Midwest flowing into the Mississippi 

River to the Gulf. These nutrients trigger 

excessive algal growth (or 

eutrophication) resulting in reduced 

sunlight, loss of aquatic habitat, and a 

decrease in oxygen dissolved in the 

water. Hypoxia threatens commercial 

and recreational fisheries in the Gulf 

because fish and other aquatic species 

cannot live in the low oxygen waters. 

In 2008, the hypoxic zone was the 

second largest since measurements 

began in 1985—8,000 square miles, an 

area larger than the state of 

Massachusetts, and slightly larger than 

the 2007 measurement.522 The 

Mississippi River/Gulf of Mexico 

Watershed Nutrient Task Force’s ‘‘Gulf 

Hypoxia Action Plan 2008’’ calls for a 

45% reduction in both nitrogen and 

phosphorus reaching the Gulf to reduce 

the size of the zone.523 An additional 

reduction in nitrogen and phosphorus 

reduction would be necessary as a result 

of increased corn production for ethanol 

and climate change impacts. 

Alexander, et al.524 modeled the 

sources of nutrient loadings to the Gulf 

of Mexico using the USGS SPARROW 

model. They estimated that agricultural 

sources contribute more than 70% of the 

delivered nitrogen and phosphorus. 

Corn and soybean production accounted 

for 52% of nitrogen delivery and 25% 

of the phosphorus. 

Several recent scientific reports have 

estimated the impact of increasing corn 

acres for ethanol in the Gulf of Mexico 

watershed. Donner and Kucharik’s 525

study showed increases in nitrogen 

export to the Gulf as a result of 

increasing corn ethanol production from 

2007 levels to 15 billion gallons in 2022. 

They concluded that the expansion of 

corn-based ethanol production could 

make it almost impossible to meet the 

Gulf of Mexico nitrogen reduction goals 

without a ‘‘radical shift’’ in feed 

production, livestock diet, and 

management of agricultural lands. The 

study estimated a mean dissolved 

inorganic nitrogen load increase of 10 to 

18% from 2007 to 2022 to meet the 15 

billion gallon corn ethanol goal. EPA’s 

Science Advisory Board report to the 

Mississippi River/Gulf of Mexico 

Watershed Task Force estimated that 

corn grown for ethanol will result in an 

additional national annual loading of 

almost 300 million pounds of nitrogen. 

An estimated 80% of that nitrogen 

loading or 238 million pounds will 

occur in the Mississippi-Atchafalaya 

River basin and contribute nitrogen to 

the hypoxia in the Gulf of Mexico.526

B. Upper Mississippi River Basin 

Analysis 

To provide a quantitative estimate of 

the impact of this proposal and 

production of corn ethanol generally on 

water quality, EPA conducted an 

analysis that modeled the changes in 

loadings of nitrogen, phosphorus, and 

sediment from agricultural production 

in the Upper Mississippi River Basin 

(UMRB). The UMRB drains 

approximately 189,000 square miles, 

including large parts of the states of 

Illinois, Iowa, Minnesota, Missouri, and 

Wisconsin. Small portions of Indiana, 

Michigan, and South Dakota are also 

within the basin. EPA selected the 

UMRB because it is representative of the 

many potential issues associated with 

ethanol production, including its 

connection to major water quality 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25103 

527Mississippi River/Gulf of Mexico Watershed 

Nutrient Task Force, supra note 6. 528 Gassman, P.W., Reyes, M.R., Green, C.H., 

Arnold, J.G., 2007, The soil and water assessment 

tool: Historical development, applications, and 

future research directions. Transactions of the 

American Society of Agricultural and Biological 

Engineers, v. 50, no. 4, p. 1211–1240. http:// 

www.card.iastate.edu/environment/items/ 

asabe_swat.pdf. 

concerns such as Gulf of Mexico 

hypoxia, large corn production, and 

numerous ethanol production plants. 

For more details on the analysis, see 

Chapter 6 in the DRIA. 

On average the UMRB contributes 

about 39% of the total nitrogen loads 

and 26% of the total phosphorus loads 

to the Gulf of Mexico.527 The high 

percentage of nitrogen from the UMRB 

is primarily due to the large inputs of 

fertilizer for agriculture and the 60% of 

cropland that is tile drained. Although 

nitrogen inputs to the UMRB in recent 

years is fairly level, there is a 21% 

decline in net inputs from humans. The 

Science Advisory Board report 

attributes this decline to higher amount 

of nitrogen removed during harvest, due 

to higher crop yields. For the same time 

period, phosphorus inputs increased 

12%. 

1. SWAT Model 

EPA selected the SWAT (Soil and 

Water Assessment Tool) model to assess 

nutrient loads from changes in 

agricultural production in the UMRB. 

Models are the primary tool that can be 

used to predict future impacts based on 

alternative scenarios. SWAT is a 

physical process model developed to 

quantify the impact of land management 

practices in large, complex 

watersheds.528

2. Baseline Model Scenario 

In order to assess alternative potential 

future conditions within the UMRB, 

EPA developed a SWAT model of a 

Baseline Scenario against which to 

analyze the impact of increased corn 

production for biofuel. For simplicity’s 

sake, we refer to the baseline as 2005, 

but like most water quality modeling, 

we had to use a range of data sets for 

the inputs. As noted above corn acres 

did not increase significantly until the 

2007 crop year. While this baseline does 

not directly quantify the impacts of this 

proposal on water quality, it is useful in 

understanding the magnitude of the 

impacts of corn production for biofuels. 

EPA plans to conduct additional 

analyses for the final rule that will 

compare the reference case biofuel 

volumes to the RFS2 volumes. 

The SWAT model was applied (i.e., 

calibrated) to the UMRB using 1960 to 

2001 weather data and flow and water 

quality data from 13 USGS gages on the 

mainstem of the Mississippi River. The 

42-year SWAT model runs were 

performed and the results analyzed to 

establish runoff, sediment, nitrogen, and 

phosphorous loadings from each of the 

131 8-digit HUC subwatersheds and the 

larger 4-digit subbasins, along with the 

total outflow from the UMRB and at the 

various USGS gage sites along the 

Mississippi River. These results 

provided the Baseline Scenario model 

values to which the future alternatives 

are compared. 

3. Alternative Scenarios 

SWAT scenario analyses were 

performed for the years 2010, 2015, 

2020, and 2022 with corn ethanol 

volumes of 12 billion gallons a year 

(BGY) for 2010, and 15 BGY for 2015 to 

2022. These volumes were adjusted for 

the UMRB based on a 42.3% ratio of 

ethanol production capacity within the 

UMRB compared to national capacity. 

The resulting UMRB ethanol production 

goals were converted into the 

corresponding required corn production 

acreage, i.e. the extent of corn acreage 

needed to meet those ethanol 

production goals. Annual increases in 

corn yield of 1.23% were built into the 

future scenarios. Fewer corn acres were 

needed to meet ethanol production 

goals after the 2015 scenario due to 

those yield increases. 

Table X.B.3–1 and Table X.B.3–2 

summarize the model outputs both 

within the UMRB and at the outlet of 

the UMRB in the Mississippi River at 

Grafton, Illinois for each of the four 

scenario years: 2010, 2015, 2020, and 

2022. It is important to note that these 

results only estimate loadings from the 

Upper Mississippi River basin, not the 

entire Mississippi River watershed. As 

noted earlier, the UMRB contributes 

about 39% of the total nitrogen loads 

and 26% of total phosphorus loads to 

the Gulf of Mexico. Due to the timing of 

this proposal, we were not able to assess 

the local impact in smaller watersheds 

within the UMRB. Those impacts may 

be significantly different. The 

decreasing nitrogen load over time is 

likely attributed to the increased corn 

yield production, resulting in greater 

plant uptake of nitrogen. 

TABLE X.B.3–1—CHANGES IN NUTRIENT LOADINGS WITHIN THE UPPER MISSISSIPPI RIVER BASIN FROM THE 2005 

BASELINE SCENARIO

2005 Baseline 2010 2015 2020 2022 

Nitrogen ............................................................ 1897.0 million lbs ............................................. +5.1% +4.2% +2.2% +1.6% 

Phosphorus ....................................................... 176.6 million lbs ............................................... +2.3% +1.1% +0.6% +0.4% 

About 24% of nitrogen and 25% of 

phosphorus leaving agricultural fields 

was assimilated (taken by aquatic plants 

or volatilized) before reaching the outlet 

of the UMRB. The assimilated nitrogen 

is not necessarily eliminated as an 

environmental concern. Five percent or 

more of the nitrogen can be converted 

to nitrous gas, a powerful greenhouse 

gas that has 300 times the climatewarming potential of carbon dioxide, 

the major greenhouse. Thus, a water 

pollutant becomes an air pollutant until 

it is either captured through biological 

sequestration or converted fully to 

elemental nitrogen. 

Total sediment outflow showed very 

little change over all scenarios. This is 

likely due to the corn being modeled as 

well-managed crop in terms of sediment 

loss, primarily due to the corn stover 

remaining on the fields following 

harvest. 

TABLE X.B.3–2—CHANGES FROM THE 2005 BASELINE TO THE MISSISSIPPI RIVER AT GRAFTON, ILLINOIS FROM THE

UPPER MISSISSIPPI RIVER BASIN

2005 Baseline 2010 2015 2020 2022 

Average corn yield (bushels/acre) .................... 141 .................................................................... 150 158 168 171 

25104 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

TABLE X.B.3–2—CHANGES FROM THE 2005 BASELINE TO THE MISSISSIPPI RIVER AT GRAFTON, ILLINOIS FROM THE

UPPER MISSISSIPPI RIVER BASIN—Continued 

2005 Baseline 2010 2015 2020 2022 

Nitrogen ............................................................ 1,433.5 million lbs ............................................ +5.5% +4.7% +2.5% +1.8% 

Phosphorus ....................................................... 132.4 million lbs ............................................... +2.8% +1.7% +0.98% +0.8% 

Sediment ........................................................... 6.4 million tons ................................................. +0.5% +0.3% +0.2% +0.1% 

After evaluating comments on this 

proposal, if time and resources permit, 

EPA may conduct additional water 

quality analyses using the SWAT model 

in the UMRB. Potential future analyses 

could include: (1) Determination of the 

most sensitive assumptions in the 

model, (2) water quality impacts from 

the changes in ethanol volumes between 

the reference case and this proposal, (3) 

removing corn stover for cellulosic 

ethanol, and (4) a case study of a smaller 

watershed to evaluate local water 

quality impacts that are impossible to 

ascertain at the scale of the UMRB. 

EPA solicits comments on the 

scenarios developed for this proposal 

and additional future analyses. At this 

time, we are not able to assess the 

impact of these additional loadings on 

the size of the Gulf of Mexico hypoxia 

zone or water quality within the UMRB. 

EPA also solicits comments on the 

significance of the modeled increases in 

nitrogen and phosphorus loads. 

C. Additional Water Issues 

Water quality and quantity impacts 

resulting from corn ethanol production 

go beyond our ability to model. The 

following issues are summarized to 

provide additional context about the 

broader range of potential impacts. See 

Chapter 6 in the DRIA for more 

discussion of these issues. 

1. Chesapeake Bay Watershed 

Agricultural lands contribute more 

nutrients to the Chesapeake Bay than 

any other land use. Chesapeake Bay 

Program partners have pledged to 

significantly reduce nutrients to the Bay 

to meet water quality goals. To estimate 

the increase in nutrient loads to the Bay 

from changes to agricultural crop 

production from 2005 to 2008, the 

Chesapeake Bay Program Watershed 

Model Phase 4.3 and Vortex models 

were utilized. Total nitrogen loads 

increased by almost 2.4 million pounds 

from an increase of almost 66,000 corn 

acres. As agriculture land use shifts 

from hay and pasture to more 

intensively fertilized row crops, this 

analysis estimates that nitrogen loads 

increase by 8.8 million pounds. 

2. Ethanol Production 

There are three principal sources of 

discharges to water from ethanol plants: 

Reject water from water purification, 

cooling water blowdown, and off-batch 

ethanol. Most ethanol facilities use onsite wells to produce the process water 

for the ethanol process. Groundwater 

sources are generally not suitable for 

process water because of their mineral 

content. Therefore, the water must be 

treated, commonly by reverse osmosis. 

For every two gallons of pure water 

produced, about a gallon of brine is 

discharged as reject water from this 

process. Most estimates of water 

consumption in ethanol production are 

based on the use of clean process water 

and neglect the water discharged as 

reject water. 

The largest source of wastewater 

discharge is reverse osmosis reject water 

from process water purification. The 

reverse osmosis process concentrates 

groundwater minerals to levels where 

they can have water quality impacts. 

There is really no means of ‘‘treating’’ 

these ions to reduce toxicity, other than 

further concentration and disposal, or 

use of instream dilution. Some facilities 

have had to construct long pipelines to 

get access to dilution so they can meet 

water quality standards. Ethanol plants 

also discharge cooling water blowdown, 

where some water is discharged to avoid 

the buildup of minerals in the cooling 

system. These brines are similar to the 

reject water described above. In 

addition, if off-batch ethanol product or 

process water is discharged, the waste 

stream can have high Biochemical 

Oxygen Demand (BOD) levels. BOD 

directly affects the amount of dissolved 

oxygen in rivers and streams. The 

greater the BOD, the more rapidly 

oxygen is depleted in the stream. The 

consequences of high BOD are the same 

as those for low dissolved oxygen: 

Aquatic organisms become stressed, 

suffocate, and die. 

Older generation production facilities 

used four to six gallons of process water 

to produce a gallon of ethanol, but 

newer facilities use less than three 

gallons of water in the production 

process. Most of this water savings is 

gained through improved recycling of 

water and heat in the process. Water 

supply is a local issue, and there have 

been concerns with water consumption 

as new plants go online. Some facilities 

are tapping into deeper aquifers as a 

source of water. These deeper water 

resources tend to contain higher levels 

of minerals and this can further increase 

the concentration of minerals in reverse 

osmosis reject water. Geographic 

impacts of water use vary. A typical 

plant producing 50 million gallons of 

ethanol per year uses a minimum of 175 

million gallons of water annually. In 

Iowa, water consumption from ethanol 

refining accounts for about seven 

percent of all industrial water use, and 

is projected to be 14% by 2012—or 

about 50 million gallons per day. 

a. Distillers Grain with Solubles 

Distillers grain with solubles (DGS) is 

an important co-product of ethanol 

production. About one-third of the corn 

processed into ethanol is converted into 

DGS. DGS has become an increasingly 

important feed component for confined 

livestock. DGS are higher in crude 

protein (nitrogen) and three to four 

times higher in phosphorus relative to 

traditional feeds. When nitrogen and 

phosphorus are fed in excess of the 

animal’s needs, these nutrients are 

excreted in the manure. When manure 

is applied to crops at rates above their 

nutrient needs or at times the crop can 

not use the nutrients, the nutrients can 

runoff to surface waters or leach into 

ground waters. 

Livestock producers can limit the 

potential pollution from manure 

applications to crops by implementing 

comprehensive nutrient management. 

Due to the substantially higher 

phosphorus content of manure from 

livestock fed DGS, producers will 

potentially need significantly more 

acres to apply the manure so that 

phosphorus will not be applied at rates 

above the needs of the crops. This is a 

particularly important concern in areas 

where concentrated livestock 

production already produces more 

phosphorus in the manure than can be 

taken up by crops or pasture land in the 

vicinity. 

Several recent studies have indicated 

that DGS may have an impact on food 

safety. Cattle fed DGS have a higher 

prevalence of a major food-borne 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25105 

529 Jacob, M. D., Fox, J. T., Drouillard, J. S., 

Renter, D. G., Nagaraja, T. G., 2008, Effects of dried 

distillers’ grain on fecal prevalence and growth of 

Escherichia coli O157 in batch culture 

fermentations from cattle, Applied and 

Environmental Microbiology, v. 74, no. 1, p. 38–43, 

available online at: http://aem.asm.org/cgi/content/ 

abstract/74/1/38 

530Ruiz-Aguilar, G. M. L.; O’Reilly, K.; Alvarez, 

P. J. J., 2003, Forum: A comparison of benzene and 

toluene plume lengths for sites contaminated with 

regular vs. ethanol-amended gasoline, Ground 

Water Monitoring and Remediation, v. 23, p. 48–53. 

531Committee on Water Implications of Biofuels 

Production in the United States, supra note 2. 

pathogen, E. coli O157, than cattle 

without DGS in their diets.529 More 

research is needed to confirm these 

studies and devise methods to eliminate 

the potential risks. 

b. Ethanol Leaks and Spills 

The potential for exposure to fuel 

components and/or additives can occur 

when underground fuel storage tanks 

leak fuel into ground water that is used 

for drinking water supplies or when 

spills occur that contaminate surface 

drinking water supplies. Ethanol 

biodegrades quickly and is not 

necessarily the pollutant of greatest 

concern in these occurrences. Instead, 

ethanol’s high biodegradability can 

cause the plume of BTEX (benzene, 

toluene, ethylbenzene and xylenes) 

compounds in fuel to extend farther (by 

as much as 70%) 530 and persist longer 

in ground water, thereby increasing 

potential exposures to these 

compounds. 

With the increasing use of ethanol in 

the fuel supply nationwide, it is 

important to understand the impact of 

ethanol on the existing tank 

infrastructure. Given the corrosivity of 

ethanol, there is concern regarding the 

increased potential for leaks from 

existing gas stations and subsequent 

impacts on drinking water supplies. In 

2007, there were 7,500 reported releases 

from underground storage tanks. 

Therefore, EPA is undertaking analyses 

designed to assess the potential impacts 

of ethanol blends on tank infrastructure 

and leak detection systems and 

determine the resulting water quality 

impacts. 

3. Biodiesel Plants 

Biodiesel plants use much less water 

than ethanol plants. Water is used for 

washing impurities from the finished 

product. Water use is variable, but is 

usually less than one gallon of water for 

each gallon of biodiesel produced. 

Larger well-designed plants use water 

more sparingly, while smaller producers 

use more water. Some facilities recycle 

washwater, which reduces water 

consumption. The strength of process 

wastewater from biodiesel plants is 

highly variable. Most production 

processes produce washwater that has 

very high BOD levels. The high strength 

of these wastes can overload and disrupt 

municipal treatment plants. 

Crude glycerin is an important side 

product from the biodiesel process and 

is about 10% of the final product. The 

rapid development of the biodiesel 

industry has caused a glut of glycerin 

production and many facilities dispose 

of glycerin. Poor handling of crude 

glycerin has resulted in upset of sewage 

treatment plants and fish kills. 

4. Water Quantity 

Water demand for crop production for 

ethanol could potentially be much 

larger than biorefinery demand. 

According to the National Research 

Council, the demand for water to 

irrigate crops for biofuels will not have 

an impact on national water use, but it 

is likely to have significant local and 

regional impacts.531 The impact is crop 

and region specific, but could be 

especially great in areas where new 

acres are irrigated. 

5. Drinking Water 

Increased corn production for ethanol 

may increase the occurrence of nitrate, 

nitrite, and the herbicide atrazine in 

sources of drinking water. Under the 

Safe Drinking Water Act, EPA has 

established enforceable standards for 

these contaminants to protect public 

health. Increases in occurrence of these 

contaminants may raise costs to public 

water systems through increased 

treatment needs or increased pumping 

costs where ethanol production is 

accelerating the long running depletion 

of aquifers. There is also a risk of 

decreased supplies of drinking water in 

communities where aquifers are being 

depleted and potential contamination 

due to leaks from gasoline stations using 

higher blends of ethanol. 

D. Request for Comment on Options for 

Reducing Water Quality Impacts 

EPA is seeking comment on how best 

to reduce the impacts of biofuels on 

water quality. EPA is seeking comment 

on the use of section 211(c) of the Clean 

Air Act, as amended by EISA, to address 

these water quality issues. Section 

211(c) gives the EPA administrator the 

discretion to ‘‘control’’ the manufacture 

and sale of a motor vehicle 

transportation fuel based on a finding 

that the fuel, or its emission product, 

‘‘causes or contributes’’ to air pollution 

or water pollution that may reasonably 

be anticipated to endanger the public 

health or welfare. 

In evaluating this option, EPA is 

seeking comment on whether it would 

be appropriate to find that emission 

products from such transportation fuels, 

including renewable fuels, are ‘‘causing 

or contributing’’ to ‘‘water pollution’’ 

and that this water pollution ‘‘may 

reasonably be anticipated to endanger 

the public health or welfare.’’ EPA is 

also seeking comment on whether it 

would be allowable and appropriate to 

‘‘control or prohibit the manufacture 

* * * ’’ of a fuel by requiring that 

manufacturers of such fuels, such as 

manufacturers of a biofuel, use, or 

certify that they used, only corn 

feedstocks grown using farming 

practices designed to reduce nutrient 

water pollution. For example, is this a 

reasonable way to ‘‘offset’’ water 

pollution caused, in part, by air 

deposition of nitrogen to water from 

combustion of transportation fuels with 

reductions of nitrogen runoff to water 

from corn feedstock by means of such 

‘‘controls’’ on the manufacture of 

biofuels adopted pursuant to section 

211(c). In the alternative, would this be 

a reasonable way to attempt to offset 

water pollution caused by the 

production of the feedstock associated 

with the production of the biofuel based 

on section 211(c). 

EPA is seeking comment and 

suggestions on how biofuel 

manufacturers might establish that their 

biofuel feedstock was grown with 

appropriate practices to control nutrient 

runoff (e.g., require a program similar to 

the one used for compliance with the 

restrictions in the definition of 

renewable biomass on previously 

cleared agricultural land). Finally, EPA 

is seeking comments on other 

approaches, mechanisms, or authorities 

that might be adopted in the renewable 

fuels rule that are likely to have the 

effect of reducing the water quality 

impacts of biofuels. 

XI. Public Participation 

We request comment on all aspects of 

this proposal. This section describes 

how you can participate in this process. 

A. How Do I Submit Comments? 

We are opening a formal comment 

period by publishing this document. We 

will accept comments during the period 

indicated under DATES in the first part 

of this proposal. If you have an interest 

in the proposed program described in 

this document, we encourage you to 

comment on any aspect of this 

rulemaking. We also request comment 

on specific topics identified throughout 

this proposal. 

Your comments will be most useful if 

you include appropriate and detailed 

25106 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

supporting rationale, data, and analysis. 

Commenters are especially encouraged 

to provide specific suggestions for any 

changes to any aspect of the regulations 

that they believe need to be modified or 

improved. You should send all 

comments, except those containing 

proprietary information, to our Air 

Docket (see ADDRESSES in the first part 

of this proposal) before the end of the 

comment period. 

You may submit comments 

electronically, by mail, or through hand 

delivery/courier. To ensure proper 

receipt by EPA, identify the appropriate 

docket identification number in the 

subject line on the first page of your 

comment. Please ensure that your 

comments are submitted within the 

specified comment period. Comments 

received after the close of the comment 

period will be marked ‘‘late.’’ EPA is not 

required to consider these late 

comments. If you wish to submit 

Confidential Business Information (CBI) 

or information that is otherwise 

protected by statute, please follow the 

instructions in Section XI.B. 

B. How Should I Submit CBI to the 

Agency? 

Do not submit information that you 

consider to be CBI electronically 

through the electronic public docket, 

www.regulations.gov, or by e-mail. 

Send or deliver information identified 

as CBI only to the following address: 

U.S. Environmental Protection Agency, 

Assessment and Standards Division, 

2000 Traverwood Drive, Ann Arbor, MI, 

48105, Attention Docket ID EPA–HQ– 

OAR–2005–0161. You may claim 

information that you submit to EPA as 

CBI by marking any part or all of that 

information as CBI (if you submit CBI 

on disk or CD–ROM, mark the outside 

of the disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is CBI). Information so marked will not 

be disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

In addition to one complete version of 

the comments that include any 

information claimed as CBI, a copy of 

the comments that does not contain the 

information claimed as CBI must be 

submitted for inclusion in the public 

docket. If you submit the copy that does 

not contain CBI on disk orCD–ROM, 

mark the outside of the disk or CD–ROM 

clearly that it does not contain CBI. 

Information not marked as CBI will be 

included in the public docket without 

prior notice. If you have any questions 

about CBI or the procedures for claiming 

CBI, please consult the person identified 

in the FOR FURTHER INFORMATION

CONTACT section. 

C. Will There Be a Public Hearing? 

We will hold a public hearing in 

Washington DC on June 9, 2009 at the 

location shown below. The hearing will 

start at 10 a.m. local time and continue 

until everyone has had a chance to 

speak. 

The Dupont Hotel, 1500 New 

Hampshire Avenue, NW., Washington, 

DC 20036, Phone# 202–483–6000. 

If you would like to present testimony 

at the public hearing, we ask that you 

notify the contact person listed under 

FOR FURTHER INFORMATION CONTACT in 

the first part of this proposal at least 8 

days before the hearing. You should 

estimate the time you will need for your 

presentation and identify any needed 

audio/visual equipment. We suggest 

that you bring copies of your statement 

or other material for the EPA panel and 

the audience. It would also be helpful 

if you send us a copy of your statement 

or other materials before the hearing. 

We will make a tentative schedule for 

the order of testimony based on the 

notifications we receive. This schedule 

will be available on the morning of the 

hearing. In addition, we will reserve a 

block of time for anyone else in the 

audience who wants to give testimony. 

We will conduct the hearing 

informally, and technical rules of 

evidence will not apply. We will 

arrange for a written transcript of the 

hearing and keep the official record of 

the hearing open for 30 days to allow 

you to submit supplementary 

information. You may make 

arrangements for copies of the transcript 

directly with the court reporter. 

D. Comment Period 

The comment period for this rule will 

end on July 27, 2009. 

E. What Should I Consider as I Prepare 

My Comments for EPA? 

You may find the following 

suggestions helpful for preparing your 

comments: 

• Explain your views as clearly as 

possible. 

• Describe any assumptions that you 

used. 

• Provide any technical information 

and/or data you used that support your 

views. 

• If you estimate potential burden or 

costs, explain how you arrived at your 

estimate. 

• Provide specific examples to 

illustrate your concerns. 

• Offer alternatives. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

• To ensure proper receipt by EPA, 

identify the appropriate docket 

identification number in the subject line 

on the first page of your response. It 

would also be helpful if you provided 

the name, date, and Federal Register 

citation related to your comments. 

XII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under section 3(f)(1) of Executive 

Order (EO) 12866 (58 FR 51735, October 

4, 1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 

economy of $100 million or more. 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under EO 12866 and 

any changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

In addition, EPA prepared an analysis 

of the potential costs and benefits 

associated with this action. This 

analysis is contained in the Draft 

Regulatory Impact Analysis, which is 

available in the docket for this 

rulemaking and at the docket internet 

address listed under ADDRESSES in the 

first part of this proposal. A more 

complete assessment of the costs and 

benefits associated with this Action will 

be completed for the Final Rule. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by EPA has been 

assigned EPA ICR number 2333.01. A 

draft Supporting Statement has been 

placed in the docket for public 

comment. 

The Agency proposes to collect 

information to ensure compliance with 

the provisions in this rule. This 

includes a variety of requirements for 

transportation fuel refiners, blenders, 

marketers, distributors, importers, and 

exporters. The types of information 

proposed to be collected includes, but is 

not limited to: registrations, periodic 

compliance reports, product transfer 

documentation, transactional 

information involving RINs and 

associated volumes of renewable fuel, 

and attest engagements. We invite 

comment on the proposed collection of 

information associated with this 

proposed rule. 

Section 208(a) of the Clean Air Act 

requires that fuel producers provide 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25107 

information the Administrator may 

reasonably require to determine 

compliance with the regulations; 

submission of the information is 

therefore mandatory. We will consider 

confidential all information meeting the 

requirements of section 208(c) of the 

Clean Air Act. 

As shown in Table XII.B–1, the total 

annual burden associated with this 

proposal is about 323,922 hours and 

$27,073,827, based on a projection of 

20,216 respondents. The estimated 

burden for fuel producers is a total 

estimate for both new and existing 

reporting requirements. Burden means 

the total time, effort, or financial 

resources expended by persons to 

generate, maintain, retain, or disclose or 

provide information to or for a Federal 

agency. This includes the time needed 

to review instructions; develop, acquire, 

install, and utilize technology and 

systems for the purposes of collecting, 

validating, and verifying information, 

processing and maintaining 

information, and disclosing and 

providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

TABLE XII.B–1—ESTIMATED BURDEN FOR REPORTING AND RECORDKEEPING REQUIREMENTS

Industry sector Number of 

respondents 

Annual burden 

hours 

Annual 

costs 

($) 

Fuels: 

Producers of renewable fuels ...................................................................................................... 5,472 112,461 8,893,531 

Importers of renewable fuelsa ..................................................................................................... 1,131 22,503 1,824,913 

Obligated parties, exportersb ....................................................................................................... 1,410 36,796 2,868,116 

RIN ownersc ................................................................................................................................. 12,083 148,542 13,102,447 

Foreign refinersd .......................................................................................................................... 65 3,460 364,940 

Foreign RIN owners ..................................................................................................................... 30 135 18,105 

Retail stations (pump label) ......................................................................................................... 25 25 1,775 

Total ...................................................................................................................................... 20,216 323,922 27,073,827 

a Includes foreign producers. 

b Refiners, exporters fall under this category. 

c Includes blenders, brokers, marketers, etc. Anyone can own RINs. 

d Includes small foreign refiners. 

In addition to the estimates shown 

above, we have separately estimated the 

costs of potential third party disclosure 

that is associated with the proposed 

registration requirements explained in 

this notice of proposed rulemaking. 

Potentially affected parties include 

farmers, private forest owners, and other 

biofuel feedstock producers. We 

estimate a total of 43,466 respondents, 

83,633 annual burden hours, and 

$5,937,943 in annual burden cost 

associated with the proposed third party 

disclosure. These estimates are 

explained in an addendum to the draft 

Supporting Statement, which has also 

been placed in the public docket. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, including the use of 

automated collection techniques, EPA 

has established a public docket for this 

rule, which includes this proposed ICR, 

under Docket ID number EPA–HQ– 

OAR–2005–0161. Submit any comments 

related to the ICR for this proposed rule 

to EPA and OMB. See ADDRESSES at the 

beginning of this notice for where to 

submit comments to EPA. Send 

comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street, NW., Washington, DC 

20503, Attention: Desk Office for EPA. 

Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after May 26, 2009, a 

comment to OMB is best assured of 

having its full effect if OMB receives it 

by June 25, 2009. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act 

1. Overview 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201 (see table below); (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

The following table provides an 

overview of the primary SBA small 

business categories potentially affected 

by this regulation: 

Industry a Defined as small entity by SBA if: NAICSa codes 

Gasoline and diesel fuel refiners ............................................................................. ≤1,500 employees .................................... 324110 

a North American Industrial Classification System. 

25108 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

532EPAct defined a ‘‘small refinery’’ as a refinery 

with a crude throughput of no more than 75,000 

barrels of crude per day (at CAA section 

211(o)(1)(K)). This definition is based on facility 

size and is different than SBA’s small refiner 

definition (which is based on company size). A 

small refinery could be owned by a larger refiner 

that exceeds SBA’s small entity standards. SBA’s 

size standards were established to set apart those 

businesses which are most likely to be at an 

inherent economic disadvantage relative to larger 

businesses. 

533This Direct Final Rule corrects minor 

typographical errors and provides clarification on 

existing provisions in the RFS1 regulations. 

2. Background 

Section 1501 of the Energy Policy Act 

of 2005 (EPAct) amended section 211 of 

the Clean Air Act (CAA) by adding 

section 211(o) which required the 

Environmental Protection Agency (EPA) 

to promulgate regulations implementing 

a renewable fuel program. EPAct 

specified that the regulations must 

ensure a specific volume of renewable 

fuel to be used in gasoline sold in the 

U.S. each year, with the total volume 

increasing over time. The goal of the 

program was to reduce dependence on 

foreign sources of petroleum, increase 

domestic sources of energy, and help 

transition to alternatives to petroleum in 

the transportation sector. 

The final Renewable Fuels Standard 

(RFS1) program rule was published on 

May 1, 2007, and the program began on 

September 1, 2007. Per EPAct, the RFS1 

program created a specific annual level 

for minimum renewable fuel use that 

increases over time—resulting in a 

requirement that 7.5 billion gallons of 

renewable fuel be blended into gasoline 

(for highway use only) by 2012. Under 

the RFS1 program, compliance is based 

on meeting the required annual 

renewable fuel volume percent standard 

(published annually in the Federal 

Register by EPA) through the use of 

Renewable Identification Numbers, or 

RINs, 38-digit serial numbers assigned 

to each batch of renewable fuel 

produced. For obligated parties (those 

who must meet the annual volume 

percent standard), RINs must be 

acquired to show compliance. 

The Energy Independence and 

Security Act of 2007 (EISA) amended 

section 211(o), and the RFS program, by 

requiring higher volumes of renewable 

fuels, to result in 36 billion gallons of 

renewable fuel by 2022. EISA also 

expanded the purview of the RFS1 

program by requiring that these 

renewable fuels be blended into 

gasoline and diesel fuel (both highway 

and nonroad). This expanded the pool 

of regulated entities, so the obligated 

parties under this RFS2 NPRM will now 

include certain refiners, importers, and 

blenders of these fuels that were not 

previously covered by the RFS1 

program. In addition to the total 

renewable fuel standard required by 

EPAct, EISA added standards for three 

additional types of renewable fuels to 

the program (advanced biofuel, 

cellulosic biofuel, and biomass-based 

diesel) and requires compliance with all 

four standards. 

Pursuant to section 603 of the RFA, 

EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines 

the impact of the proposed rule on small 

entities along with regulatory 

alternatives that could reduce that 

impact. The IRFA is available for review 

in the docket (in Chapter 7 of the Draft 

Regulatory Impact Analysis) and is 

summarized below. 

As required by section 609(b) of the 

RFA, as amended by SBREFA, EPA also 

conducted outreach to small entities 

and convened a Small Business 

Advocacy Review Panel to obtain advice 

and recommendations of representatives 

of the small entities that potentially 

would be subject to the rule’s 

requirements. 

Consistent with the RFA/SBREFA 

requirements, the Panel evaluated the 

assembled materials and small-entity 

comments on issues related to elements 

of the IRFA. A copy of the Panel Report 

is included in the docket for this 

proposed rule, and a summary of the 

Panel process, and subsequent Panel 

recommendations, is summarized 

below. 

3. Summary of Potentially Affected 

Small Entities 

The small entities that will potentially 

be subject to the renewable fuel 

standard include: Domestic refiners that 

produce gasoline and/or diesel and 

importers of gasoline and/or diesel into 

the United States. Based on 2007 data, 

EPA believes that there are about 95 

refiners of gasoline and diesel fuel. Of 

these, EPA believes that there are 

currently 21 refiners producing gasoline 

and/or diesel fuel that meet the SBA 

small entity definition of having 1,500 

employees or less. Further, we believe 

that three of these refiners own 

refineries that do not meet the 

Congressional ‘‘small refinery’’ 

definition.532 It should be noted that 

because of the dynamics in the refining 

industry (i.e., mergers and acquisitions), 

the actual number of refiners that 

ultimately qualify for small refiner 

status under the RFS2 program could be 

different than this initial estimate. 

4. Potential Reporting, Recordkeeping, 

and Compliance 

For any fuel control program, EPA 

must have assurance that any fuel 

produced meets all applicable standards 

and requirements, and that the fuel 

continues to meet those standards and 

requirements as it passes downstream 

through the distribution system to the 

ultimate end user. Registration, 

reporting, and recordkeeping are 

necessary to track compliance with the 

RFS2 requirements and transactions 

involving RINs. As discussed above in 

Sections III.J and IV.E, the proposed 

compliance requirements under the 

RFS2 program are in many ways similar 

to those required under the RFS1 

program, with some modifications to 

account for the new requirements of 

EISA. 

5. Related Federal Rules 

We are aware of a few other current 

or proposed Federal rules that are 

related to the upcoming proposed rule. 

The primary federal rules that are 

related to the proposed RFS2 rule under 

consideration are the first Renewable 

Fuel Standard (RFS1) rule (72 FR 23900, 

May 1, 2007) and the RFS1 Technical 

Amendment Direct Final Rulemaking 

(73 FR 57248, October 2, 2008).533

6. Summary of SBREFA Panel Process 

and Panel Outreach 

a. Significant Panel Findings 

The Small Business Advocacy Review 

Panel (SBAR Panel, or the Panel) 

considered regulatory options and 

flexibilities to help mitigate potential 

adverse effects on small businesses as a 

result of this rule. During the SBREFA 

Panel process, the Panel sought out and 

received comments on the regulatory 

options and flexibilities that were 

presented to SERs and Panel members. 

The recommendations of the Panel are 

described below and are also located in 

Section 9 of the SBREFA Final Panel 

Report, which is available in the public 

docket. 

b. Panel Process 

As required by section 609(b) of the 

RFA, as amended by SBREFA, we also 

conducted outreach to small entities 

and convened an SBAR Panel to obtain 

advice and recommendations of 

representatives of the small entities that 

potentially would be subject to the 

rule’s requirements. On July 9, 2008, 

EPA’s Small Business Advocacy 

Chairperson convened a Panel under 

Section 609(b) of the RFA. In addition 

to the Chair, the Panel consisted of the 

Division Director of the Assessment and 

Standards Division of EPA’s Office of 

Transportation and Air Quality, the 

Chief Counsel for Advocacy of the Small 

Business Administration, and the 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25109 

Administrator of the Office of 

Information and Regulatory Affairs 

within the Office of Management and 

Budget. As part of the SBAR Panel 

process, we conducted outreach with 

representatives from representatives of 

small businesses that would potentially 

be affected by the proposed rulemaking. 

We met with these Small Entity 

Representatives (SERs) to discuss the 

potential rulemaking approaches and 

potential options to decrease the impact 

of the rulemaking on their industries. 

We distributed outreach materials to the 

SERs; these materials included 

background on the rulemaking, possible 

regulatory approaches, and possible 

rulemaking alternatives. The Panel met 

with SERs from the industries that 

would be directly affected by the RFS2 

rule on July 30, 2008 to discuss the 

outreach materials and receive feedback 

on the approaches and alternatives 

detailed in the outreach packet (the 

Panel also met with SERs on June 3, 

2008 for an initial outreach meeting). 

The Panel received written comments 

from the SERs following the meeting in 

response to discussions had at the 

meeting and the questions posed to the 

SERs by the Agency. The SERs were 

specifically asked to provide comment 

on regulatory alternatives that could 

help to minimize the rule’s impact on 

small businesses. 

In general, SERs stated that they 

believed that small refiners would face 

challenges in meeting the new 

standards. More specifically, they 

voiced concerns with respect to the RIN 

program itself, uncertainty (with the 

required renewable fuel volumes, RIN 

availability, and cost), and the desire for 

a RIN system review. 

The Panel’s findings and discussions 

were based on the information that was 

available during the term of the Panel 

and issues that were raised by the SERs 

during the outreach meetings and in 

their comments. One concern that was 

raised by EPA with regard to provisions 

for small refiners in the RFS2 rule is 

that this rule presents a very different 

issue than the small refinery versus 

small refiner concept from RFS1. This 

issue deals with whether EPA has the 

authority to provide small refineries that 

are operated by a small refiner with an 

extension of time that would be 

different from (and more than) the 

temporary exemption specified by 

Congress in section 211(o)(9) for small 

refineries. For those small refiners who 

are covered by the small refinery 

provisions, Congress has specifically 

adopted a relief provision aimed at their 

refineries. This provides a temporary 

extension through December 31, 2010 

and allows for further extensions only if 

certain criteria are met. EPA believes 

that providing small refineries (and 

thus, small refiners who own small 

refineries) with an additional exemption 

different from that provided by section 

211(o)(9) raises concerns about 

inconsistency with the intent of 

Congress. Congress spoke directly to the 

relief that EPA may provide for small 

refineries, including those small 

refineries operated by small refiners, 

and limited it to a blanket exemption 

through December 31, 2010, with 

additional extensions if the criteria 

specified by Congress were met. An 

additional or different extension, relying 

on a more general provision in section 

211(o)(3), would raise questions about 

consistency with the intent of Congress. 

It was agreed that EPA should 

consider the issues raised by the SERs 

and discussions had by the Panel itself, 

and that EPA should consider 

comments on flexibility alternatives that 

would help to mitigate negative impacts 

on small businesses to the extent legally 

allowable by the Clean Air Act. 

Alternatives discussed throughout the 

Panel process included those offered in 

previous or current EPA rulemakings, as 

well as alternatives suggested by SERs 

and Panel members. A summary of 

these recommendations is detailed 

below, and a full discussion of the 

regulatory alternatives and hardship 

provisions discussed and recommended 

by the Panel can be found in the 

SBREFA Final Panel Report. A complete 

discussion of the provisions for which 

we are requesting comment and/or 

proposing in this action can be found in 

Section IV.B of this preamble. Also, the 

Panel Report includes all comments 

received from SERs (Appendix B of the 

Report) and summaries of the two 

outreach meetings that were held with 

the SERs. In accordance with the RFA/ 

SBREFA requirements, the Panel 

evaluated the aforementioned materials 

and SER comments on issues related to 

the IRFA. The Panel’s recommendations 

from the Final Panel Report are 

discussed below. 

c. Panel Recommendations 

The purpose of the Panel process is to 

solicit information as well as suggested 

flexibility options from the SERs, and 

the Panel recommended that EPA 

continue to do so during the 

development of the RFS2 rule. 

Recognizing the concerns about EPA’s 

authority to provide extensions to a 

subset of small refineries (i.e., those that 

are owned by small refiners) different 

from that provided to small refineries in 

section 211(o)(9), the Panel 

recommended that EPA continue to 

evaluate this issue, and that EPA request 

comment on its authority and the 

appropriateness of providing extensions 

beyond those authorized by section 

211(o)(9) for small refineries operated 

by a small refiner. The Panel also 

recommended that EPA propose to 

provide the same extension provision of 

211(o)(9) to small refiners who do not 

own small refineries as is provided for 

small refiners who do own small 

refineries. 

i. Delay in Standards 

The RFS1 program regulations 

provide small refiners who operate 

small refineries as well as small refiners 

who do not operate small refineries with 

a temporary exemption from the 

standard through December 31, 2010. 

Small refiner SERs suggested that an 

additional temporary exemption for the 

RFS2 program would be beneficial to 

them in meeting the standards. EPA 

evaluated a temporary exemption for at 

least some of the four required RFS2 

standards for small refiners. The Panel 

recommended that EPA propose a delay 

in the effective date of the standards 

until 2014 for small entities, to the 

maximum extent allowed by the statute. 

However, the Panel recognized that EPA 

has serious concerns about its authority 

to provide an extension of the 

temporary exemption for small 

refineries that is different from that 

provided in CAA section 211(o)(9), 

since Congress specifically addressed an 

extension for small refineries in that 

provision. 

The Panel did recommend that EPA 

propose other avenues through which 

small refineries and small refiners could 

receive extensions of the temporary 

exemption. These avenues, as discussed 

in greater detail in Sections XII.C.6.c.v 

and vi below, are a possible extension 

of the temporary exemption for an 

additional two years following a study 

of small refineries by the Department of 

Energy (DOE) and provisions for caseby-case economic hardship relief. 

ii. Phase-in 

Small refiner SERs’ suggested that a 

phase-in of the obligations applicable to 

small refiners would be beneficial for 

compliance, such that small refiners 

would comply by gradually meeting the 

standards on an incremental basis over 

a period of time, after which point they 

would comply fully with the RFS2 

standards, EPA has serious concerns 

about its authority to allow for such a 

phase-in of the standards. CAA section 

211(o)(3)(B) states that the renewable 

fuel obligation shall ‘‘consist of a single 

applicable percentage that applies to all 

categories of persons specified’’ as 

obligated parties. This kind of phase-in 

25110 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

approach would result in different 

applicable percentages being applied to 

different obligated parties. Further, as 

discussed above, such a phase-in 

approach would provide more relief to 

small refineries operated by small 

refiners than that provided under the 

small refinery provision. Thus the Panel 

recommended that EPA should invite 

comment on a phase-in, but not propose 

such a provision. 

iii. RIN-Related Flexibilities 

The small refiner SERs requested that 

the proposed rule contain provisions for 

small refiners related to the RIN system, 

such as flexibilities in the RIN rollover 

cap percentage and allowing all small 

refiners to use RINs interchangeably. 

Currently in the RFS1 program, EPA 

allows for 20% of a previous year’s RINs 

to be ‘‘rolled over’’ and used for 

compliance in the following year. A 

provision to allow for flexibilities in the 

rollover cap could include a higher RIN 

rollover cap for small refiners for some 

period of time or for at least some of the 

four standards. Since the concept of a 

rollover cap was not mandated by 

section 211(o), EPA believes that there 

may be an opportunity to provide 

appropriate flexibility in this area to 

small refiners under the RFS2 program 

but only if it is determined in the DOE 

small refinery study that there is a 

disproportionate effect warranting relief. 

The Panel recommended that EPA 

request comment on increasing the RIN 

rollover cap percentage for small 

refiners, and further that EPA should 

request comment on an appropriate 

level of that percentage. 

The Panel recommended that EPA 

invite comment on allowing RINs to be 

used interchangeably for small refiners, 

but not propose this concept because 

under this approach small refiners 

would arguably be subject to a different 

applicable percentage than other 

obligated parties. This concept would 

also fail to require the four different 

standards mandated by Congress (e.g., 

conventional biofuel could not be used 

instead of cellulosic biofuel or biomassbased diesel). 

iv. Program Review 

With regard to the suggested program 

review, EPA raised the concern that this 

could lead to some redundancy since 

EPA is required to publish a notice of 

the applicable RFS standards in the 

Federal Register annually, and that this 

annual process will inevitably include 

an evaluation of the projected 

availability of renewable fuels. 

Nevertheless, the SBA and OMB Panel 

members stated that they believe that a 

program review could be helpful to 

small entities in providing them some 

insight to the RFS program’s progress 

and alleviate some uncertainty 

regarding the RIN system. As EPA will 

be publishing a Federal Register notice 

annually, the Panel recommended that 

EPA include an update of RIN system 

progress (e.g., RIN trading, RIN 

availability, etc.) in this notice and that 

the results of this evaluation be 

considered in any request for case-bycase hardship relief. 

v. Extensions of the Temporary 

Exemption Based on a Study of Small 

Refinery Impacts 

The Panel recommended that EPA 

propose in the RFS2 program the 

provision at 40 CFR 80.1141(e) 

extending the RFS1 temporary 

exemption for at least two years for any 

small refinery that DOE determines 

would be subject to disproportionate 

economic hardship if required to 

comply with the RFS2 requirements. 

Section 211(o)(9)(A)(ii) required that 

by December 31, 2008, DOE was to 

perform a study of the economic 

impacts of the RFS requirements on 

small refineries to assess and determine 

whether the RFS requirements would 

impose a disproportionate economic 

hardship on small refineries, and submit 

this study to EPA. Section 211(o)(9) also 

provided that small refineries found to 

be in a disproportionate economic 

hardship situation would receive an 

extension of the temporary exemption 

for at least two years. 

The Panel also recommended that 

EPA work with DOE in the development 

of the small refinery study, specifically 

to communicate the comments that 

SERs raised during the Panel process. 

vi. Extensions of the Temporary 

Exemption Based on Disproportionate 

Economic Hardship 

While SERs did not specifically 

comment on the concept of hardship 

provisions for the upcoming proposal, 

the Panel noted that under CAA section 

211(o)(9)(B) small refineries may 

petition EPA for case-by-case extensions 

of the small refinery temporary 

exemption on the basis of 

disproportionate economic hardship. 

Refiners may petition EPA for this caseby-case hardship relief at any time. 

The Panel recommended that EPA 

propose in the RFS2 program a case-bycase hardship provision for small 

refineries similar to that provided at 40 

CFR 80.1141(e)(1). The Panel also 

recommended that EPA propose a caseby-case hardship provision for small 

refiners that do not operate small 

refineries that is comparable to that 

provided for small refineries under 

section 211(o)(9)(B), using its discretion 

under CAA section 211(o)(3)(B). This 

would apply if EPA does not adopt an 

automatic extension for small refiners, 

and would allow those small refiners 

that do not operate small refineries to 

apply for the same kind of extension as 

a small refinery. The Panel 

recommended that EPA take into 

consideration the results of the annual 

update of RIN system progress and the 

DOE small refinery study in assessing 

such hardship applications. 

We invite comments on all aspects of 

the proposal and its impacts on small 

entities. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), P.L. 104– 

4, establishes requirements for Federal 

agencies to assess the effects of their 

regulatory actions on State, local, and 

tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. 

Before EPA establishes any regulatory 

requirements that may significantly or 

uniquely affect small governments, 

including tribal governments, it must 

have developed under section 203 of the 

UMRA a small government agency plan. 

The plan must provide for notifying 

potentially affected small governments, 

enabling officials of affected small 

governments to have meaningful and 

timely input in the development of EPA 

regulatory proposals with significant 

Federal intergovernmental mandates, 

and informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Today’s proposal contains no Federal 

mandates (under the regulatory 

provisions of Title II of the UMRA) for 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25111 

State, local, or tribal governments. The 

rule imposes no enforceable duty on any 

State, local or tribal governments. EPA 

has determined that this rule contains 

no regulatory requirements that might 

significantly or uniquely affect small 

governments. EPA has determined that 

this proposal contains a Federal 

mandate that may result in expenditures 

of $100 million or more for the private 

sector in any one year. EPA believes that 

the proposal represents the least costly, 

most cost-effective approach to achieve 

the statutory requirements of the rule. 

The costs and benefits associated with 

the proposal are discussed above and in 

the Draft Regulatory Impact Analysis, as 

required by the UMRA. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ 

This proposed rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. Thus, Executive 

Order 13132 does not apply to this rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicits comment on this 

proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ 

This proposed rule does not have 

tribal implications, as specified in 

Executive Order 13175. This rule will be 

implemented at the Federal level and 

impose compliance costs only on 

transportation fuel refiners, blenders, 

marketers, distributors, importers, and 

exporters. Tribal governments would be 

affected only to the extent they purchase 

and use regulated fuels. Thus, Executive 

Order 13175 does not apply to this rule. 

EPA specifically solicits additional 

comment on this proposed rule from 

tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks and 

because it implements specific 

standards established by Congress in 

statutes. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355 (May 

22, 2001)) because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. In 

fact, this rule has a positive effect on 

energy supply and use. By promoting 

the diversification of transportation 

fuels, this rule enhances energy supply. 

Therefore, we have concluded that this 

rule is not likely to have any adverse 

energy effects. Our energy effects 

analysis is described above in Section 

IX. 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law No. 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This rulemaking proposes changes to 

the Renewable Fuel Standard (RFS) 

program at Title 40 of the Code of 

Federal Regulations, Subpart K which 

already contains voluntary consensus 

standard ASTM D6751–06a ‘‘Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate 

Fuels’’. This standard was developed by 

ASTM International (originally known 

as the American Society for Testing and 

Materials), Subcommittee D02.E0, and 

was approved in August 2006. The 

standard may be obtained through the 

ASTM Web site (www.astm.org) or by 

calling ASTM at (610) 832–9585. 

This proposed rulemaking does not 

propose to change this voluntary 

consensus standard, and does not 

involve any other technical standards. 

Therefore, EPA is not considering the 

use of any voluntary consensus 

standards other than that described 

above. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. EPA 

lacks the discretionary authority to 

address environmental justice in this 

proposed rulemaking since the Agency 

is implementing specific standards 

established by Congress in statutes. 

Although EPA lacks authority to modify 

today’s regulatory decision on the basis 

of environmental justice considerations, 

EPA nevertheless determined that this 

proposed rule does not have a 

disproportionately high and adverse 

human health or environmental impact 

on minority or low-income populations. 

XIII. Statutory Authority 

Statutory authority for this action 

comes from section 211 of the Clean Air 

Act, 42 U.S.C. 7545. Additional support 

for the procedural and compliance 

related aspects of today’s proposal, 

including the proposed recordkeeping 

requirements, come from Sections 114, 

25112 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

208, and 301(a) of the Clean Air Act, 42 

U.S.C. 7414, 7542, and 7601(a). 

List of Subjects in 40 CFR Part 80 

Environmental protection, Air 

pollution control, Diesel fuel, Fuel 

additives, Gasoline, Imports, 

Incorporation by reference, Labeling, 

Motor vehicle pollution, Penalties, 

Reporting and recordkeeping 

requirements. 

Dated: May 5, 2009. 

Lisa P. Jackson, 

Administrator. 

For the reasons set forth in the 

preamble, 40 CFR part 80 is proposed to 

be amended as follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 7542, 7545, and 

7601(a). 

2. A new Subpart M is added to part 

80 to read as follows: 

Subpart M—Renewable Fuel Standard 

Sec. 

80.1400 Applicability. 

80.1401 Definitions. 

80.1402 [Reserved] 

80.1403 Which fuels are not subject to the 

20% GHG thresholds? 

80.1404 [Reserved] 

80.1405 What are the Renewable Fuel 

Standards? 

80.1406 To whom do the Renewable 

Volume Obligations apply? 

80.1407 How are the Renewable Volume 

Obligations calculated? 

80.1408–80.1414 [Reserved] 

80.1415 How are equivalence values 

assigned to renewable fuel? 

80.1416 Treatment of parties who produce 

or import new renewable fuels and 

pathways. 

80.1417–80.1424 [Reserved] 

80.1425 Renewable Identification Numbers 

(RINs). 

80.1426 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

80.1427 How are RINs used to demonstrate 

compliance? 

80.1428 General requirements for RIN 

distribution. 

80.1429 Requirements for separating RINs 

from volumes of renewable fuel. 

80.1430 Requirements for exporters of 

renewable fuels. 

80.1431 Treatment of invalid RINs. 

80.1432 Reported spillage or disposal of 

renewable fuel. 

80.1433–80.1439 [Reserved] 

80.1440 What are the provisions for 

blenders who handle and blend less than 

125,000 gallons of renewable fuel per 

year? 

80.1441 Small refinery exemption. 

80.1442 What are the provisions for small 

refiners under the RFS program? 

80.1443 What are the opt-in provisions for 

noncontiguous states and territories? 

80.1444–80.1448 [Reserved] 

80.1449 What are the Production Outlook 

Report requirements? 

80.1450 What are the registration 

requirements under the RFS program? 

80.1451 What are the recordkeeping 

requirements under the RFS program? 

80.1452 What are the reporting 

requirements under the RFS program? 

80.1453 What are the product transfer 

document (PTD) requirements for the 

RFS program? 

80.1454 What are the provisions for 

renewable fuel production facilities and 

importers who produce or import less 

than 10,000 gallons of renewable fuel per 

year? 

80.1455 What are the provisions for 

cellulosic biofuel allowances? 

80.1456–80.1459 [Reserved] 

80.1460 What acts are prohibited under the 

RFS program? 

80.1461 Who is liable for violations under 

the RFS program? 

80.1462 [Reserved] 

80.1463 What penalties apply under the 

RFS program? 

80.1464 What are the attest engagement 

requirements under the RFS program? 

80.1465 What are the additional 

requirements under this subpart for 

foreign small refiners, foreign small 

refineries, and importers of RFS– 

FRFUEL? 

80.1466 What are the additional 

requirements under this subpart for 

foreign producers and importers of 

renewable fuels? 

80.1467 What are the additional 

requirements under this subpart for a 

foreign RIN owner? 

80.1468 [Reserved] 

80.1469 What are the labeling requirements 

that apply to retailers and wholesale 

purchaser-consumers of ethanol fuel 

blends that contain greater than 10 

volume percent ethanol? 

Subpart M—Renewable Fuel Standard 

§ 80.1400 Applicability. 

The provisions of this Subpart M shall 

apply for all renewable fuel produced 

on or after January 1, 2010, for all RINs 

generated after January 1, 2010, and for 

all renewable volume obligations and 

compliance periods starting with 

January 1, 2010. Except as provided 

otherwise in this Subpart M, the 

provisions of Subpart K of this Part 80 

shall not apply for such renewable fuel, 

RINs, renewable volume obligations, or 

compliance periods. 

§ 80.1401 Definitions. 

The definitions of § 80.2 and of this 

section apply for the purposes of this 

subpart M. The definitions of this 

section do not apply to other subparts 

unless otherwise noted. Note that many 

terms defined here are common terms 

that have specific meanings under this 

subpart M (such as the terms ‘‘coprocessed,’’ ‘‘cropland,’’ and ‘‘yard 

waste’’). The definitions follow: 

Actual peak capacity means the 

maximum annual volume of renewable 

fuels produced from a specific 

renewable fuel production facility on an 

annual basis. 

(1) For facilities that commenced 

construction prior to December 19, 2007 

the maximum annual volume is for any 

year prior to 2008. 

(2) For facilities that commenced 

construction after December 19, 2007, 

and are fired with natural gas, biomass, 

or a combination thereof, the maximum 

annual volume may be for any year after 

startup over the first three years of 

operation. 

Advanced biofuel means renewable 

fuel, other than ethanol derived from 

cornstarch, that qualifies for a D code of 

3 pursuant to § 80.1426(d). 

Areas at risk of wildfire are areas 

located within, or within one mile of, 

forestland, tree plantation, or any other 

generally undeveloped tract of land that 

is at least one acre in size with 

substantial vegetative cover. 

Baseline volume means the greater of 

nameplate capacity or actual peak 

capacity of a specific renewable fuel 

production facility. 

(1) For facilities that commenced 

construction on or before December 19, 

2007, the actual peak capacity may be 

for any year prior to 2008. 

(2) For facilities that commenced 

construction after December 19, 2007, 

and are fired with natural gas, biomass, 

or a combination thereof, the actual 

peak capacity may be for any year after 

startup for the facility over the first 

three years of operation. 

Biomass-based diesel means a 

renewable fuel which meets the 

requirements in paragraph (1) or (2) of 

this definition: 

(1) A transportation fuel or fuel 

additive which is all of the following: 

(i) Registered as a motor vehicle fuel 

or fuel additive under 40 CFR part 79. 

(ii) A mono-alkyl ester and meets 

ASTM D–6751–07, entitled ‘‘Standard 

Specification for Biodiesel Fuel 

Blendstock (B100) for Middle Distillate 

Fuels.’’ ASTM D–6751–07 is 

incorporated by reference. This 

incorporation by reference was 

approved by the Director of the Federal 

Register in accordance with 5 U.S.C. 

552(a) and 1 CFR Part 51. A copy may 

be obtained from the American Society 

for Testing and Materials, 100 Barr 

Harbor Drive, West Conshohocken, 

Pennsylvania. A copy may be inspected 

at the EPA Docket Center, Docket No. 

EPA–HQ–OAR–2005–0161, EPA/DC, 

EPA West, Room 3334, 1301 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25113 

Constitution Ave., NW., Washington, 

DC, or at the National Archives and 

Records Administration (NARA). For 

information on the availability of this 

material at NARA, call 866–272–6272, 

or go to: http://www.archives.gov/ 

federal-register/cfr/ibr-locations.html. 

(iii) Intended for use in engines that 

are designed to run on conventional 

diesel fuel. 

(iv) Qualifies for a D code of 2 

pursuant to § 80.1426(d). 

(2) A non-ester renewable diesel. 

(3) Renewable fuel that is coprocessed is not biomass-based diesel. 

Carbon Capture and Storage (CCS) is 

the process of capturing carbon dioxide 

from an emission source, (typically) 

converting it to a supercritical state, 

transporting it to an injection site, and 

injecting it into deep subsurface rock 

formations for long-term storage. 

Cellulosic biofuel means renewable 

fuel derived from any cellulose, hemicellulose, or lignin that is derived from 

renewable biomass and that qualifies for 

a D code of 1 pursuant to § 80.1426(d). 

Combined heat and power (CHP), also 

known as cogeneration, refers to 

industrial processes in which byproduct 

heat that would otherwise be released 

into the environment is used for process 

heating and/or electricity production. 

Commence construction, as applied to 

facilities that produce renewable fuel, 

means that the owner or operator has all 

necessary preconstruction approvals or 

permits (as defined at 40 CFR 

52.21(a)(10)), that for multi-phased 

projects, the commencement of 

construction of one phase does not 

constitute commencement of 

construction of any later phase, unless 

each phase is mutually dependent for 

physical and chemical reasons only, and 

has satisfied either of the following: 

(1) Begun, or caused to begin, a 

continuous program of actual 

construction on-site (as defined in 40 

CFR 52.21(a)(11)) of the facility to be 

completed within a reasonable time. 

(2) Entered into binding agreements or 

contractual obligations, which cannot be 

cancelled or modified without 

substantial loss to the owner or 

operator, to undertake a program of 

actual construction of the facility to be 

completed within a reasonable time. 

Co-processed means that renewable 

biomass was simultaneously processed 

with petroleum feedstock in the same 

unit or units to produce a fuel that is 

partially renewable. 

Crop residue is the residue left over 

from the harvesting of planted crops. 

Cropland is land used for production 

of crops for harvest and includes 

cultivated cropland, such as for row 

crops or close-grown crops, and noncultivated cropland, such as for 

horticultural crops. 

Diesel refers to any and all of the 

products specified at § 80.1407(f). 

Ecologically sensitive forestland 

means forestland that is: 

(1) An ecological community listed in 

a document entitled ‘‘Listing of Forest 

Ecological Communities Pursuant to 40 

CFR 80.1401,’’ (available in public 

docket EPA–HQ–OAR–2005–0161); or 

(2) Old growth or late successional, 

characterized by trees at least 200 years 

in age. 

Existing agricultural land is cropland, 

pastureland, or land enrolled in the 

Conservation Reserve Program 

(administered by the U.S. Department of 

Agriculture’s Farm Service Agency) that 

was cleared or cultivated prior to 

December 19, 2007, and that, since 

December 19, 2007, has been 

continuously: 

(1) Nonforested; and 

(2) Actively managed as agricultural 

land or fallow, as evidenced by any of 

the following: 

(i) Records of sales of planted crops, 

crop residue, or livestock, or records of 

purchases for land treatments such as 

fertilizer, weed control, or reseeding. 

(ii) A written management plan for 

agricultural purposes. 

(iii) Documented participation in an 

agricultural management program 

administered by a Federal, state, or local 

government agency. 

(iv) Documented management in 

accordance with a certification program 

for agricultural products. 

Export of renewable fuel means: 

(1) Transfer of any renewable fuel to 

a location outside the contiguous 48 

states and Hawaii; and 

(2) Transfer of any renewable fuel 

from a location in the contiguous 48 

states to Alaska or a United States 

territory, unless that state or territory 

has received an approval from the 

Administrator to opt-in to the renewable 

fuel program pursuant to § 80.1443. 

Facility means all of the activities and 

equipment associated with the 

production of renewable fuel starting 

from the point of delivery of feedstock 

material to the point of final storage of 

the end product, which are located on 

one property, and are under the control 

of the same party (or parties under 

common control). 

Fallow means cropland, pastureland, 

or land enrolled in the Conservation 

Reserve Program (administered by the 

U.S. Department of Agriculture’s Farm 

Service Agency) that is intentionally left 

idle to regenerate for future agricultural 

purposes with no seeding or planting, 

harvesting, mowing, or treatment during 

the fallow period. 

Forestland is generally undeveloped 

land covering a minimum area of 1 acre 

upon which the primary vegetative 

species are trees, including land that 

formerly had such tree cover and that 

will be regenerated. Forestland does not 

include tree plantations. 

Gasoline refers to any and all of the 

products specified at § 80.1407(c). 

Importers. An importer of 

transportation fuel or renewable fuel is: 

(1) Any party who brings 

transportation fuel or renewable fuel 

into the 48 contiguous states of the 

United States and Hawaii, from a 

foreign country or from an area that has 

not opted in to the program 

requirements of this subpart pursuant to 

§ 80.1443; and 

(2) Any party who brings 

transportation fuel or renewable fuel 

into an area that has opted in to the 

program requirements of this subpart 

pursuant to § 80.1443. 

Motor vehicle has the meaning given 

in Section 216(2) of the Clean Air Act 

(42 U.S.C. 7550(2)). 

Nameplate capacity means: 

(1) The maximum rated annual 

volume output of renewable fuel 

produced by a renewable fuel 

production facility under specific 

conditions as indicated in applicable air 

permits issued by the U.S. 

Environmental Protection Agency, state, 

or local air pollution control agencies 

and that govern the construction and/or 

operation of the renewable fuel facility. 

(2) If the maximum rated annual 

volume output of renewable fuel is not 

specified in any applicable air permits 

issued by the U.S. Environmental 

Protection Agency, state, or local air 

pollution control agencies, then 

nameplate capacity is the actual peak 

capacity of the facility. 

Neat renewable fuel is a renewable 

fuel to which only a de minimis amount 

of gasoline (as defined in Section 

211(k)(10)(F) of the Clean Air Act (42 

U.S.C. 7550)) or diesel fuel has been 

added. 

Non-ester renewable diesel means 

renewable fuel which is all the 

following: 

(1) Registered as a motor vehicle fuel 

or fuel additive under 40 CFR Part 79. 

(2) Not a mono-alkyl ester. 

(3) Intended for use in engines that 

are designed to run on conventional 

diesel fuel. 

(4) Derived from nonpetroleum 

renewable resources. 

(5) Qualifies for a D code of 3 as 

defined in § 80.1426(d). 

Nonforested land means land that is 

not forestland. 

Nonpetroleum renewable resources 

include, but are not limited to the 

following: 

25114 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(1) Plant oils. 

(2) Animal fats and animal wastes, 

including poultry fats and poultry 

wastes, and other waste materials. 

Nonroad vehicle has the meaning 

given in Section 216(11) of the Clean 

Air Act (42 U.S.C. 7550(11)). 

Ocean-going vessel means, for this 

subpart only, a vessel propelled by a 

Category 3 (C3) (as defined in 40 CFR 

1042.901) marine engine that uses 

residual fuel (as defined at § 80.2(bbb)) 

or operates internationally. Note that 

ocean-going vessels may also include 

smaller engines such as Category 2 

auxiliary engines. 

Pastureland is land managed for the 

production of indigenous or introduced 

forage plants for livestock grazing or hay 

production, and to prevent succession 

to other plant types. 

Planted crops are all annual or 

perennial agricultural crops that may be 

used as feedstocks for renewable fuel, 

such as grains, oilseeds, sugarcane, 

switchgrass, prairie grass, and other 

species providing that they were 

intentionally applied to the ground by 

humans either by direct application as 

seed or nursery stock, or through 

intentional natural seeding by mature 

plants left undisturbed for that purpose. 

Planted trees are trees planted by 

humans from nursery stock or by seed 

either through direct application to the 

ground or by intentional natural seeding 

by mature trees left undisturbed for that 

purpose. 

Pre-commercial thinnings are trees, 

including unhealthy or diseased trees, 

primarily removed to reduce stocking to 

concentrate growth on more desirable, 

healthy trees. 

Renewable biomass means each of the 

following: 

(1) Planted crops and crop residue 

harvested from existing agricultural 

land. 

(2) Planted trees and slash from a tree 

plantation located on non-federal land 

(including land belonging to an Indian 

tribe or an Indian individual that is held 

in trust by the U.S. or subject to a 

restriction against alienation imposed 

by the U.S.) that was cleared at any time 

prior to December 19, 2007, and has 

been continuously actively managed 

since December 19, 2007. Active 

management is evidenced by any of the 

following: 

(i) Records of sales of planted trees or 

slash, or records of purchases of seeds, 

seedlings, or other nursery stock. 

(ii) A written management plan for 

silvicultural purposes. 

(iii) Documented participation in a 

silvicultural program administered by a 

Federal, state, or local government 

agency. 

(iv) Documented management in 

accordance with a certification program 

for silvicultural products. 

(3) Animal waste material and animal 

byproducts. 

(4) Slash and pre-commercial 

thinnings from non-federal forestland 

(including forestland belonging to an 

Indian tribe or an Indian individual, 

that are held in trust by the United 

States or subject to a restriction against 

alienation imposed by the United 

States) that is not ecologically sensitive 

forestland. 

(5) Biomass (organic matter that is 

available on a renewable or recurring 

basis) obtained from within 200 feet of 

buildings, campgrounds, and other areas 

regularly occupied by people, or of 

public infrastructure, such as utility 

corridors, bridges, and roadways, in 

areas at risk of wildfire. 

(6) Algae. 

(7) Separated yard waste or food 

waste, including recycled cooking and 

trap grease. 

Renewable fuel means a fuel which 

meets all of the following: 

(1) Fuel that is produced from 

renewable biomass. 

(2) Fuel that is used to replace or 

reduce the quantity of fossil fuel present 

in a transportation fuel, home heating 

oil, or jet fuel. 

(3) Ethanol covered by this definition 

shall be denatured as required and 

defined in 27 CFR parts 19 through 21. 

Any volume of denaturant added to the 

undenatured ethanol by a producer or 

importer in excess of 5 volume percent 

shall not be included in the volume of 

ethanol for purposes of determining 

compliance with the requirements 

under this subpart. 

Renewable Identification Number 

(RIN), is a unique number generated to 

represent a volume of renewable fuel 

pursuant to §§ 80.1425 and 80.1426. 

(1) Gallon-RIN is a RIN that represents 

an individual gallon of renewable fuel; 

and 

(2) Batch-RIN is a RIN that represents 

multiple gallon-RINs. 

Slash is the residue, including 

treetops, branches, and bark, left on the 

ground after logging or accumulating as 

a result of a storm, fire, delimbing, or 

other similar disturbance. 

Small refinery means a refinery for 

which the average aggregate daily crude 

oil throughput for calendar year 2006 

(as determined by dividing the aggregate 

throughput for the calendar year by the 

number of days in the calendar year) 

does not exceed 75,000 barrels. 

Transportation fuel means fuel for use 

in motor vehicles, motor vehicle 

engines, nonroad vehicles, or nonroad 

engines (except for ocean-going vessels). 

Tree plantation is a stand of no fewer 

than 100 planted trees of similar age 

comprising one or two tree species or an 

area managed for growth of such trees 

covering a minimum of 1 acre. 

Yard waste is leaves, sticks, pine 

needles, grass and hedge clippings, and 

similar waste from residential, 

commercial, or industrial areas. 

§ 80.1402 [Reserved] 

§ 80.1403 Which fuels are not subject to 

the 20% GHG thresholds? 

(a) Pursuant to the definition of 

baseline volume in § 80.1401, the 

baseline volume of renewable fuel that 

is produced from facilities which 

commenced construction on or before 

December 19, 2007, shall not be subject 

to the 20 percent reduction in GHG 

emissions and shall be deemed 

grandfathered for purposes of generating 

RINs pursuant to § 80.1426(d)(7)(ii) if 

the owner or operator: 

(1) Did not discontinue construction 

for a period of 18 months or more after 

December 19, 2007; and 

(2) Completed construction within 36 

months of December 19, 2007. 

(b) The volume of ethanol that is 

produced from facilities which 

commenced construction after 

December 19, 2007 and on or before 

December 31, 2009, shall not be subject 

to the 20 percent reduction in GHG 

emissions and shall be deemed 

grandfathered for purposes of generating 

RINs pursuant to § 80.1426(d)(7)(ii) only 

if such facilities are fired with natural 

gas, biomass, or a combination thereof. 

(c) The annual volume of renewable 

fuel during a calendar year from 

facilities described in paragraph (a) of 

this section that is beyond the baseline 

volume shall be subject to the 20 

percent reduction in GHG emissions 

and such volume shall not be deemed 

grandfathered for purposes of generating 

RINs pursuant to § 80.1426(d)(7)(ii). 

(d) For those facilities described in 

paragraph (a) of this section which 

produce ethanol and are fired with 

natural gas, biomass, or a combination 

thereof, increases in the annual volume 

of ethanol above the baseline volume 

during a calendar year shall not be 

subject to the 20 percent reduction in 

GHG emissions and shall be deemed 

grandfathered for purposes of generating 

RINs pursuant to § 80.1426(d)(7)(ii), 

provided that: 

(1) The facility continues to be fired 

only with natural gas, biomass, or a 

combination thereof; and 

(2) If the increases in volume at the 

facility are due to new construction, 

such new construction must have 

commenced on or before December 31, 

2009. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25115 

(e) If there are any changes in the mix 

of renewable fuels produced by those 

facilities described in paragraph (d) of 

this section, only the ethanol volume 

will not be subject to the 20 percent 

reduction in GHG emissions and shall 

be deemed grandfathered for purposes 

of generating RINs pursuant to 

§ 80.1426(d)(7)(ii). 

§ 80.1404 [Reserved] 

§ 80.1405 What are the Renewable Fuel 

Standards? 

(a) Renewable Fuel Standards for 

2010. (1) The value of the cellulosic 

biofuel standard for 2010 shall be 0.06 

percent. 

(2) The value of the biomass-based 

diesel standard for 2010 shall be 0.71 

percent. 

(3) The value of the advanced biofuel 

standard for 2010 shall be 0.59 percent. 

(4) The value of the renewable fuel 

standard for 2010 shall be 8.01 percent. 

(b) Beginning with the 2011 

compliance period, EPA will calculate 

the value of the annual standards and 

publish these values in the Federal 

Register by November 30 of the year 

preceding the compliance period. 

(c) EPA will base the calculation of 

the standards on information provided 

by the Energy Information 

Administration regarding projected 

gasoline and diesel volumes and 

projected volumes of renewable fuels 

expected to be used in gasoline and 

diesel blending for the upcoming year. 

(d) EPA will calculate the annual 

renewable fuel standards using the 

following equations: 

Std 100%

RFV

CB, i

CB, i = ∗ ( ) G RG GS RGS GE D RD DS i i i i ii i i − + − ( ) − +− ( ) + ( ) − RDS DE i i −

Std 100%

RFV

BBD, i

BBD, i = ∗ ( ) G RG GS RGS GE D RD D i i i i ii i − + − ( ) − +− ( ) + ( ) S RDS DE i ii − −

Std 100%

RFV

AB, i

AB, i = ∗ ( ) G RG GS RGS GE D RD DS i i i i ii i i − + − ( ) − +− ( ) + ( ) − RDS DE i i −

Std 100%

RFV

RF, i

RF, i = ∗ ( ) G RG GS RGS GE D RD DS i i i i ii i i − + − ( ) − +− ( ) + ( ) − RDS DE i i −

Where: 

StdCB,i = The cellulosic biofuel standard for 

year i, in percent. 

StdBBD,i = The biomass-based diesel standard 

for year i, in percent. 

StdAB,i = The advanced biofuel standard for 

year i, in percent. 

StdRF,i = The renewable fuel standard for year 

i, in percent. 

RFVCB,i = Annual volume of cellulosic 

biofuel required by section 211(o)(2)(B) 

of the Clean Air Act for year i, in gallons. 

RFVBBD,i = Annual volume of biomass-based 

diesel required by section 211(o)(2)(B) of 

the Clean Air Act for year i, in gallons. 

RFVAB,i = Annual volume of advanced 

biofuel required by section 211(o)(2)(B) 

of the Clean Air Act for year i, in gallons. 

RFVRF,i = Annual volume of renewable fuel 

required by section 211(o)(2)(B) of the 

Clean Air Act for year i, in gallons. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

Di = Amount of diesel projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RGi = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RDi = Amount of renewable fuel blended into 

diesel that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

GSi = Amount of gasoline projected to be 

used in Alaska or a U.S. territory, in year 

i, if the state or territory has opted-in or 

opts-in, in gallons. 

RGSi = Amount of renewable fuel blended 

into gasoline that is projected to be 

consumed in Alaska or a U.S. territory, 

in year i, if the state or territory opts-in, 

in gallons. 

DSi = Amount of diesel projected to be used 

in Alaska or a U.S. territory, in year i, if 

the state or territory has opted-in or optsin, in gallons. 

RDSi = Amount of renewable fuel blended 

into diesel that is projected to be 

consumed in Alaska or a U.S. territory, 

in year i, if the state or territory opts-in, 

in gallons. 

GEi = The amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners, in year i, in gallons in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. Assumed to equal 

0.119 * (Gi¥RGi). 

DEi = The amount of diesel fuel projected to 

be produced by exempt small refineries 

and small refiners in year i, in gallons, 

in any year they are exempt per 

§§ 80.1441 and 80.1442, respectively. 

Assumed to equal 0.152 * (Di–RDi). 

§ 80.1406 To whom do the Renewable 

Volume Obligations apply? 

(a)(1) An obligated party is any refiner 

that produces gasoline or diesel fuel 

within the 48 contiguous states or 

Hawaii, or any importer that imports 

gasoline or diesel fuel into the 48 

contiguous states or Hawaii. A party 

that simply adds renewable fuel to 

gasoline or diesel fuel, as defined in 

§ 80.1407(c) or (f), is not an obligated 

party. 

(2) If the Administrator approves a 

petition of Alaska or a United States 

territory to opt-in to the renewable fuel 

program under the provisions in 

§ 80.1443, then ‘‘obligated party’’ shall 

also include any refiner that produces 

gasoline or diesel fuel within that state 

or territory, or any importer that imports 

gasoline or diesel fuel into that state or 

territory. 

(b) For each compliance period 

starting with 2010, an obligated party is 

required to demonstrate, pursuant to 

§ 80.1427, that it has satisfied the 

Renewable Volume Obligations for that 

compliance period, as specified in 

§ 80.1407(a). 


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(c) An obligated party may comply 

with the requirements of paragraph (b) 

of this section for all of its refineries in 

the aggregate, or for each refinery 

individually. 

(d) An obligated party must comply 

with the requirements of paragraph (b) 

of this section for all of its imported 

gasoline or diesel fuel in the aggregate. 

(e) An obligated party that is both a 

refiner and importer must comply with 

the requirements of paragraph (b) of this 

section for its imported gasoline or 

diesel fuel separately from gasoline or 

diesel fuel produced by its refinery or 

refineries. 

(f) Where a refinery or import facility 

is jointly owned by two or more parties, 

the requirements of paragraph (b) of this 

section may be met by one of the joint 

owners for all of the gasoline or diesel 

fuel produced/imported at the facility, 

or each party may meet the 

requirements of paragraph (b) of this 

section for the portion of the gasoline or 

diesel fuel that it owns, as long as all of 

the gasoline or diesel fuel produced/ 

imported at the facility is accounted for 

in determining the Renewable Volume 

Obligations under § 80.1407. 

(g) The requirements in paragraph (b) 

of this section apply to the following 

compliance periods: Beginning in 2010, 

and every year thereafter, the 

compliance period is January 1 through 

December 31. 

(h) A party that exports renewable 

fuel (pursuant to the definition of an 

exporter of renewable fuel in § 80.1401) 

shall demonstrate, pursuant to 

§ 80.1427, that it has satisfied the 

Renewable Volume Obligations for each 

compliance period as specified in 

§ 80.1430(b). 

§ 80.1407 How are the Renewable Volume 

Obligations calculated? 

(a) The Renewable Volume 

Obligations for an obligated party are 

determined according to the following 

formulas: 

(1) Cellulosic biofuel. 

RVOCB,i = (RFStdCB,i * (GVi + DVi)) + 

DCB,i–1

Where: 

RVOCB,i = The Renewable Volume Obligation 

for cellulosic biofuel for an obligated 

party for calendar year i, in gallons. 

RFStdCB,i = The standard for cellulosic 

biofuel for calendar year i, determined 

by EPA pursuant to § 80.1405, in 

percent. 

GVi = The non-renewable gasoline volume, 

determined in accordance with 

paragraphs (b), (c), and (d) of this 

section, which is produced in or 

imported into the 48 contiguous states or 

Hawaii by an obligated party in calendar 

year i, in gallons. 

DVi = The diesel non-renewable volume, 

determined in accordance with 

paragraphs (e) and (f) of this section, 

produced in or imported into the 48 

contiguous states or Hawaii by an 

obligated party in calendar year i, in 

gallons. 

DCB,i–1 = Deficit carryover from the previous 

year for cellulosic biofuel, in gallons. 

(2) Biomass-based diesel. 

RVOBBD,i = (RFStdBBD,i * (GVi + DVi)) 

+ DBBD,i–1

Where: 

RVOBBD,i = The Renewable Volume 

Obligation for biomass-based diesel for 

an obligated party for calendar year i, in 

gallons. 

RFStdBBD,i = The standard for biomass-based 

diesel for calendar year i, determined by 

EPA pursuant to § 80.1405, in percent. 

GVi = The non-renewable gasoline volume, 

determined in accordance with 

paragraphs (b), (c), and (d) of this 

section, which is produced in or 

imported into the 48 contiguous states or 

Hawaii by an obligated party in calendar 

year i, in gallons. 

DVi = The diesel non-renewable volume, 

determined in accordance with 

paragraphs (e) and (f) of this section, 

produced in or imported into the 48 

contiguous states or Hawaii by an 

obligated party in calendar year i, in 

gallons. 

DBBD,i-1 = Deficit carryover from the previous 

year for biomass-based diesel, in gallons. 

(3) Advanced biofuel. 

RVOAB,i = (RFStdAB,i * (GVi + DVi)) + 

DAB,i–1

Where: 

RVOAB,i = The Renewable Volume Obligation 

for advanced biofuel for an obligated 

party for calendar year i, in gallons. 

RFStdAB,i = The standard for advanced 

biofuel for calendar year i, determined 

by EPA pursuant to § 80.1405, in 

percent. 

GVi = The non-renewable gasoline volume, 

determined in accordance with 

paragraphs (b), (c), and (d) of this 

section, which is produced in or 

imported into the 48 contiguous states or 

Hawaii by an obligated party in calendar 

year i, in gallons. 

DVi = The diesel non-renewable volume, 

determined in accordance with 

paragraphs (e) and (f) of this section, 

produced in or imported into the 48 

contiguous states or Hawaii by an 

obligated party in calendar year i, in 

gallons. 

DAB,i-1 = Deficit carryover from the previous 

year for advanced biofuel, in gallons. 

(4) Renewable fuel. 

RVORF,i = (RFStdRF,i * (GVi + DVi)) + 

DRF,i-1

Where: 

RVORF,i = The Renewable Volume Obligation 

for renewable fuel for an obligated party 

for calendar year i, in gallons. 

RFStdRF,i = The standard for renewable fuel 

for calendar year i, determined by EPA 

pursuant to § 80.1405, in percent. 

GVi = The non-renewable gasoline volume, 

determined in accordance with 

paragraphs (b), (c), and (d) of this 

section, which is produced in or 

imported into the 48 contiguous states or 

Hawaii by an obligated party in calendar 

year i, in gallons. 

DVi = The diesel non-renewable volume, 

determined in accordance with 

paragraphs (e) and (f) of this section, 

produced in or imported into the 48 

contiguous states or Hawaii by an 

obligated party in calendar year i, in 

gallons. 

DRF,i-1 = Deficit carryover from the previous 

year for renewable fuel, in gallons. 

(b) The non-renewable gasoline 

volume for an obligated party for a given 

year, GVi, specified in paragraph (a) of 

this section is calculated as follows: 

GV G RBG i x

x

n

y

y

m

= − = =

∑ ∑ 1 1

Where: 

x = Individual batch of gasoline produced or 

imported in calendar year i. 

n = Total number of batches of gasoline 

produced or imported in calendar year i. 

Gx = Volume of batch x of gasoline produced 

or imported, as defined in paragraph (c) 

of this section, in gallons. 

y = Individual batch of renewable fuel 

blended into gasoline in calendar year i. 

m = Total number of batches of renewable 

fuel blended into gasoline in calendar 

year i. 

RBGy = Volume of batch y of renewable fuel 

blended into gasoline, in gallons. 

(c) All of the following products that 

are produced or imported during a 

compliance period, collectively called 

‘‘gasoline’’ for the purposes of this 

section (unless otherwise specified), are 

to be included (but not double-counted) 

in the volume used to calculate a party’s 

Renewable Volume Obligations under 

paragraph (a) of this section, except as 

provided in paragraph (d) of this 

section: 

(1) Reformulated gasoline, whether or 

not renewable fuel is later added to it. 

(2) Conventional gasoline, whether or 

not renewable fuel is later added to it. 

(3) Reformulated gasoline blendstock 

that becomes finished reformulated 

gasoline upon the addition of oxygenate 

(RBOB). 

(4) Conventional gasoline blendstock 

that becomes finished conventional 

gasoline upon the addition of oxygenate 

(CBOB). 

(5) Blendstock (including butane and 

gasoline treated as blendstock (GTAB)) 

that has been combined with other 

blendstock and/or finished gasoline to 

produce gasoline. 

(6) Any gasoline, or any unfinished 

gasoline that becomes finished gasoline 

upon the addition of oxygenate, that is 


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produced or imported to comply with a 

state or local fuels program. 

(d) The following products are not 

included in the volume of gasoline 

produced or imported used to calculate 

a party’s renewable volume obligation 

under paragraph (a) of this section: 

(1) Any renewable fuel as defined in 

§ 80.1401. 

(2) Blendstock that has not been 

combined with other blendstock or 

finished gasoline to produce gasoline. 

(3) Gasoline produced or imported for 

use in Alaska, the Commonwealth of 

Puerto Rico, the U.S. Virgin Islands, 

Guam, American Samoa, and the 

Commonwealth of the Northern 

Marianas, unless the area has opted into 

the RFS program under § 80.1443. 

(4) Gasoline produced by a small 

refinery that has an exemption under 

§ 80.1441 or an approved small refiner 

that has an exemption under § 80.1442 

until January 1, 2011 (or later, for small 

refineries, if their exemption is 

extended pursuant to § 80.1441(h)). 

(5) Gasoline exported for use outside 

the 48 United States and Hawaii, and 

gasoline exported for use outside 

Alaska, the Commonwealth of Puerto 

Rico, the U.S. Virgin Islands, Guam, 

American Samoa, and the 

Commonwealth of the Northern 

Marianas, if the area has opted into the 

RFS program under § 80.1443. 

(6) For blenders, the volume of 

finished gasoline, RBOB, or CBOB to 

which a blender adds blendstocks. 

(7) The gasoline portion of transmix 

produced by a transmix processor, or 

the transmix blended into gasoline by a 

transmix blender, under § 80.84. 

(e) The diesel non-renewable volume 

for an obligated party for a given year, 

DVi, specified in paragraph (a) of this 

section is calculated as follows: 

DV D RBD i x

x

n

y

y

m

= − = =

∑ ∑ 1 1

Where: 

x = Individual batch of diesel produced or 

imported in calendar year i. 

n = Total number of batches of diesel 

produced or imported in calendar year i. 

Dx = Volume of batch x of diesel produced 

or imported, as defined in paragraph (f) 

of this section, in gallons. 

y = Individual batch of renewable fuel 

blended into diesel in calendar year i. 

m = Total number of batches of renewable 

fuel blended into diesel in calendar year 

i. 

RBDy = Volume of batch y of renewable fuel 

blended into diesel, in gallons. 

(f) All products meeting the definition 

of MVNRLM diesel fuel at § 80.2(qqq) 

that are produced or imported during a 

compliance period, collectively called 

‘‘diesel fuel’’ for the purposes of this 

section (unless otherwise specified), are 

to be included (but not double-counted) 

in the volume used to calculate a party’s 

Renewable Volume Obligations under 

paragraph (a) of this section. 

§§ 80.1408–80.1414 [Reserved] 

§ 80.1415 How are equivalence values 

assigned to renewable fuel? 

(a)(1) Each gallon of a renewable fuel, 

or gallon equivalent pursuant to 

paragraph (c) of this section, shall be 

assigned an equivalence value by the 

producer or importer pursuant to 

paragraph (b) or (c) of this section. 

(2) The equivalence value is a number 

that is used to determine how many 

gallon–RINs can be generated for a batch 

of renewable fuel according to 

§ 80.1426. 

(b) All renewable fuels shall have an 

equivalence value of 1.0. 

(c) A gallon of renewable fuel is a 

physically measured unit of volume for 

any fuel that exists as a liquid at 60 °F 

and 1 atm, but represents 77,930 Btu 

(lower heating value) for any fuel that 

exists as a gas at 60 °F and 1 atm. 

§ 80.1416 Treatment of parties who 

produce or import new renewable fuels and 

pathways. 

(a)(1) Each renewable fuel producer or 

importer that produces or imports a new 

renewable fuel, or uses a new pathway 

that can not qualify for a D code as 

defined in § 80.1426(d), must apply to 

use a D code as specified in paragraph 

(b) of this section. 

(2) EPA will review the application 

and may allow the use of an appropriate 

D code for the combination of fuel type, 

feedstock, and production process. 

(3) Except as provided in paragraph 

(c) of this section, parties that must 

apply to use a D code pursuant to 

paragraph (b) of this section may not 

generate RINs for that new fuel or new 

combination fuel type, feedstock, and 

production process until the Agency has 

reviewed the application and updated 

Table 1 to § 80.1426. 

(b)(1) The application for a new 

renewable fuel or pathway shall include 

all the following: 

(i) A completed facility registration 

under § 80.1450(b). 

(ii) A technical justification that 

includes a description of the renewable 

fuel, feedstock(s) used to make it, and 

the production process. 

(iii) Any additional information that 

the Agency needs to complete a 

lifecycle Greenhouse Gas assessment of 

the new fuel or pathway. 

(2) A company may only submit one 

application per pathway. If EPA 

determines the application to be 

incomplete, per paragraph (b)(4) of this 

section, then the company may 

resubmit. 

(3) The application must be signed 

and certified as meeting all the 

applicable requirements of this subpart 

by a responsible corporate officer of the 

applicant organization. 

(4) If EPA determines that the 

application is incomplete then EPA will 

notify the applicant in writing that the 

application is incomplete and will not 

be reviewed further. However, an 

amended application that corrects the 

omission may be re-submitted for EPA 

review. 

(5) If the fuel or pathway described in 

the application does not meet the 

definition of renewable fuel in 

§ 80.1401, then EPA will notify the 

applicant in writing that the application 

is denied and will not be reviewed 

further. 

(c)(1) A producer may use a 

temporary D code pending EPA review 

of an application under paragraph (b) of 

this section if the producer is producing 

renewable fuel from a fuel type and 

feedstock combination listed in Table 1 

to § 80.1426, but where the renewable 

fuel producer’s production process is 

not listed. A producer using a temporary 

D code, must do all the following: 

(i) Provide information necessary 

under paragraph (b) of this section and 

register under 40 CFR part 79 before 

introducing the fuel into commerce. 

(ii) Generate RINs using the temporary 

D code for all renewable fuel produced 

using this combination fuel type, 

feedstock, and production process. 

(iii) When Table 1 to § 80.1426 has 

been updated to include the new fuel 

pathway, cease to use the temporary D 

code and use the applicable D code in 

the table. 

(iv) For existing fuel type and 

feedstock combinations that apply to 

more than one D code, the producer 

must use the highest numerical value 

from the applicable D codes as the 

temporary D code. 

(2) Except if the application is 

deemed incomplete or denied pursuant 

to paragraph (b)(3) or (b)(4) of this 

section, if Table 1 to § 80.1426 is not 

updated within 5 years of the initial 

receipt of a company’s application, the 

company must stop using the temporary 

D code. 

(3) A producer whose fuel pathway is 

ethanol made from starches in a process 

that uses natural gas or coal for process 

heat may not use a temporary D code for 

their fuel pathway. 

(4) EPA may revoke the authority 

provided by this section for use of a 

temporary D code at any time if any of 

the following occur: 


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25118 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(i) EPA determines that the fuel or 

pathway described in the application 

does not meet the definition of 

renewable fuel in § 80.1401. 

(ii) EPA discovers adverse health 

effects unique to the fuel or pathway. 

(iii) The information provided by the 

applicant on the pathway in paragraph 

(b) of this section is deemed false or 

incorrect. 

(d) The application under this section 

shall be submitted on forms and 

following procedures as prescribed by 

EPA. 

§§ 80.1417–80.1424 [Reserved] 

§ 80.1425 Renewable Identification 

Numbers (RINs). 

Each RIN is a 38-character numeric 

code of the following form: 

KYYYYCCCCFFFFFBBBBBRRDSSSS

SSSSEEEEEEEE 

(a) K is a number identifying the type 

of RIN as follows: 

(1) K has the value of 1 when the RIN 

is assigned to a volume of renewable 

fuel pursuant to §§ 80.1426(e) and 

80.1428(a). 

(2) K has the value of 2 when the RIN 

has been separated from a volume of 

renewable fuel pursuant to § 80.1429. 

(b) YYYY is the calendar year in 

which the batch of renewable fuel was 

produced or imported. YYYY also 

represents the year in which the RIN 

was originally generated. 

(c) CCCC is the registration number 

assigned, according to § 80.1450, to the 

producer or importer of the batch of 

renewable fuel. 

(d) FFFFF is the registration number 

assigned, according to § 80.1450, to the 

facility at which the batch of renewable 

fuel was produced or imported. 

(e) BBBBB is a serial number assigned 

to the batch which is chosen by the 

producer or importer of the batch such 

that no two batches have the same value 

in a given calendar year. 

(f) RR is a number representing 10 

times the equivalence value of the 

renewable fuel as specified in § 80.1415. 

(g) D is a number determined 

according to § 80.1426(d) and 

identifying the type of renewable fuel, 

as follows: 

(1) D has the value of 1 to denote fuel 

categorized as cellulosic biofuel. 

(2) D has the value of 2 to denote fuel 

categorized as biomass-based diesel. 

(3) D has the value of 3 to denote fuel 

categorized as advanced biofuel. 

(4) D has the value of 4 to denote fuel 

categorized as renewable fuel. 

(h) SSSSSSSS is a number 

representing the first gallon-RIN 

associated with a batch of renewable 

fuel. 

(i) EEEEEEEE is a number 

representing the last gallon-RIN 

associated with a batch of renewable 

fuel. EEEEEEEE will be identical to 

SSSSSSSS if the batch-RIN represents a 

single gallon-RIN. Assign the value of 

EEEEEEEE as described in § 80.1426. 

§ 80.1426 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

(a) Regional applicability. (1) Except 

as provided in paragraph (b) of this 

section, a RIN must be generated by a 

renewable fuel producer or importer for 

every batch of fuel that meets the 

definition of renewable fuel that is 

produced or imported for use as 

transportation fuel, home heating oil, or 

jet fuel in the 48 contiguous states or 

Hawaii. 

(2) If the Administrator approves a 

petition of Alaska or a United States 

territory to opt-in to the renewable fuel 

program under the provisions in 

§ 80.1443, then the requirements of 

paragraph (a)(1) of this section shall also 

apply to renewable fuel produced or 

imported for use as transportation fuel, 

home heating oil, or jet fuel in that state 

or territory beginning in the next 

calendar year. 

(b) Cases in which RINs are not 

generated. (1) Volume threshold. 

Renewable fuel producers that produce 

less than 10,000 gallons of renewable 

fuel each year, and importers that 

import less than 10,000 gallons of 

renewable fuel each year, are not 

required to generate and assign RINs to 

batches of renewable fuel. Such 

producers and importers are also 

exempt from the registration, reporting, 

and recordkeeping requirements of 

§§ 80.1450 through 80.1452, and the 

attest engagement requirements of 

§ 80.1464. However, for those producers 

and importers that own RINs or 

voluntarily generate and assign RINs, all 

the requirements of this subpart apply. 

(2) Fuel producers and importers shall 

not generate RINs for fuel that they 

produce or import for which they have 

made a demonstration under 

§ 80.1451(c) that the feedstocks used to 

produce the fuel are not renewable 

biomass (as defined in § 80.1401). 

(3) Fuel producers and importers may 

not generate RINs for fuel that is not 

renewable fuel. 

(4) Importers shall not import or 

generate RINs for fuel imported from a 

foreign producer that is not registered 

with EPA as required in § 80.1450. 

(5) Importers shall not generate RINs 

for renewable fuel that has already been 

assigned RINs by a foreign producer. 

(c) Definition of batch. For the 

purposes of this section and § 80.1425, 

a ‘‘batch of renewable fuel’’ is a volume 

of renewable fuel that has been assigned 

a unique RIN code BBBBB within a 

calendar year by the producer or 

importer of the renewable fuel in 

accordance with the provisions of this 

section and § 80.1425. 

(1) The number of gallon-RINs 

generated for a batch of renewable fuel 

may not exceed 99,999,999. 

(2) A batch of renewable fuel cannot 

represent renewable fuel produced or 

imported in excess of one calendar 

month. 

(d) Generation of RINs. (1) Producers 

and importers of fuel made from 

renewable feedstocks must determine 

for each batch of fuel produced or 

imported whether or not the fuel is 

renewable fuel (as defined in § 80.1401), 

including a determination of whether or 

not the feedstock used to make the fuel 

is renewable biomass (as defined 

§ 80.1401). Except as provided in 

paragraph (b) of this section, the 

producer or importer of a batch of 

renewable fuel must generate a RIN for 

that batch. 

(i) Domestic producers must generate 

RINs for all renewable fuel that they 

produce. 

(ii) Importers must generate RINs for 

all renewable fuel that they import that 

has not been assigned RINs by a foreign 

producer, including any renewable fuel 

contained in imported transportation 

fuel. 

(iii) Foreign producers may generate 

RINs for any renewable fuel that they 

export to the 48 contiguous states of the 

United States or Hawaii. 

(2) A party generating a RIN shall 

specify the appropriate numerical 

values for each component of the RIN in 

accordance with the provisions of 

§ 80.1425(a) and this paragraph (d). 

(3) Applicable pathways. D codes 

shall be used in RINs generated by 

producers or importers of renewable 

fuel according to the pathways listed in 

Table 1 to this section. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25119 

TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS

Fuel type Feedstock Production process requirements D code 

Ethanol ................ Starch from corn, wheat, barley, oats, rice, or sorghum ............................ —Process heat derived from biomass 4 

Ethanol ................ Starch from corn, wheat, barley, oats, rice, or sorghum ............................ —Dry mill plant .................................

—Process heat derived from natural 

gas 

—Combined heat and power (CHP) 

—Fractionation of feedstocks 

—Some or all distillers grains are 

dried 

4 

Ethanol ................ Starch from corn, wheat, barley, oats, rice, or sorghum ............................ —Dry mill plant .................................

—Process heat derived from natural 

gas 

—All distillers grains are wet 

4 

Ethanol ................ Starch from corn, wheat, barley, oats, rice, or sorghum ............................ —Dry mill plant .................................

—Process heat derived from coal 

—Combined heat and power (CHP) 

—Fractionation of feedstocks 

—Membrane separation of ethanol 

—Raw starch hydrolysis ..................

—Some or all distillers grains are 

dried 

4 

Ethanol ................ Starch from corn, wheat, barley, oats, rice, or sorghum ............................ —Dry mill plant .................................

—Process heat derived from coal 

—Combined heat and power (CHP) 

—Fractionation of feedstocks 

—Membrane separation of ethanol 

—All distillers grains are wet 

4 

Ethanol ................ Cellulose and hemicellulose from corn stover, switchgrass, miscanthus, 

wheat straw, rice straw, sugarcane bagasse, slash, pre-commercial 

thinnings, yard waste, or planted trees.

—Enzymatic hydrolysis of cellulose

—Fermentation of sugars ................

—Process heat derived from lignin 

1 

Ethanol ................ Cellulose and hemicellulose from corn stover, switchgrass, miscanthus, 

wheat straw, rice straw, sugarcane bagasse, slash, pre-commercial 

thinnings, yard waste, or planted trees.

—Thermochemical gasification of 

biomass.

—Fischer-Tropsch process 

1 

Ethanol ................ Sugarcane sugar ......................................................................................... —Process heat derived from sugarcane bagasse 3 

Biodiesel (mono 

alkyl ester).

Waste grease, waste oils, tallow, chicken fat, or non-food-grade corn oil —Transesterification ........................ 2 

Biodiesel (mono 

alkyl ester).

Soybean oil and other virgin plant oils ....................................................... —Transesterification ........................ 4 

Cellulosic diesel .. Cellulose and hemicellulose from corn stover, switchgrass, miscanthus, 

wheat straw, rice straw, sugarcane bagasse, slash, pre-commercial 

thinnings, yard waste, or planted trees.

—Thermochemical gasification of 

biomass.

—Fischer-Tropsch process 

—Catalytic depolymerization 

1 or 2 

Non-ester renewable diesel.Waste grease, waste oils, tallow, chicken fat, or non-food-grade corn oil —Hydrotreating ................................

—Dedicated facility that processes 

only renewable biomass.

2 

Non-ester renewable diesel.Waste grease, waste oils, tallow, chicken fat, or non-food-grade corn oil —Hydrotreating ................................

—Co-processing facility that also 

processes petroleum feedstocks.

3 

Non-ester renewable diesel.Soybean oil and other virgin plant oils ....................................................... —Hydrotreating ................................ 4 

Cellulosic gasoline Cellulose and hemicellulose from corn stover, switchgrass, miscanthus, 

wheat straw, rice straw, sugarcane bagasse, slash, pre-commercial 

thinnings, yard waste, or planted trees.

—Thermochemical gasification of 

biomass.

—Fischer-Tropsch process 

—Catalytic depolymerization 

1 

(4) Producers whose operations can be 

described by a single pathway. 

(i) The number of gallon-RINs that 

shall be generated for a given batch of 

renewable fuel shall be equal to a 

volume calculated according to the 

following formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

(ii) The D code that shall be used in 

the RINs generated shall be the D code 

specified in Table 1 to this section 

which corresponds to the pathway that 

describes the producer’s operations. 

(5) Producers whose operations can be 

described by two or more pathways. (i) 

The D codes that shall be used in the 

RINs generated within a calendar year 

shall be the D codes specified in Table 

1 to this section which correspond to 

the pathways that describe the 

producer’s operations throughout that 

calendar year. 

(ii) If all the pathways describing the 

producer’s operations have the same D 

code, then that D code shall be used in 

all the RINs generated. The number of 

gallon-RINs that shall be generated for a 

25120 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

given batch of renewable fuel in this 

case shall be equal to a volume 

calculated according to the following 

formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

(iii) If the pathway applicable to a 

producer changes on a specific date, 

such that one pathway applies before 

the date and another pathway applies 

on and after the date, then the 

applicable D code used in generating 

RINs must change on the date that the 

change in pathway occurs. The number 

of gallon-RINs that shall be generated 

for a given batch of renewable fuel in 

this case shall be equal to a volume 

calculated according to the following 

formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for a batch with 

a single applicable D code. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

(iv) If a producer produces two or 

more different types of renewable fuel 

whose volumes can be measured 

separately, then separate values for VRIN

shall be calculated for each batch of 

each type of renewable fuel according to 

formulas in Table 2 to this section: 

TABLE 2 TO § 80.1426—NUMBER OF

GALLON-RINS TO ASSIGN TO

BATCH-RINS WITH D CODES DEPENDENT ON FUEL TYPE

D code to use in 

batch-RIN 

Number of gallonRINs 

D = 1 ......................... VRIN, CB = EV *Vs, CB

D = 2 ......................... VRIN, BBD = EV *Vs,

BBD

D = 3 ......................... VRIN, AB = EV *Vs, RF

D = 4 ......................... VRIN, RF = EV *Vs, RF

Where: 

VRIN,CB = RIN volume, in gallons, for use 

determining the number of gallon-RINs 

that shall be generated for a batch of 

cellulosic biofuel with a D code of 1. 

VRIN,BBD = RIN volume, in gallons, for use 

determining the number of gallon-RINs 

that shall be generated for a batch of 

biomass-based diesel with a D code of 2. 

VRIN,AB = RIN volume, in gallons, for use 

determining the number of gallon-RINs 

that shall be generated for a batch of 

advanced biofuel with a D code of 3. 

VRIN,RF = RIN volume, in gallons, for use 

determining the number of gallon-RINs 

that shall be generated for a batch of 

renewable fuel with a D code of 4. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs,CB = Standardized volume of the batch of 

renewable fuel at 60 °F that must be 

assigned a D code of 1 based on its fuel 

type, in gallons, calculated in accordance 

with paragraph (d)(10) of this section. 

Vs,BBD = Standardized volume of the batch of 

renewable fuel at 60 °F that must be 

assigned a D code of 2 based on its fuel 

type, in gallons, calculated in accordance 

with paragraph (d)(10) of this section. 

Vs,AB = Standardized volume of the batch of 

renewable fuel at 60 °F that must be 

assigned a D code of 3 based on its fuel 

type, in gallons, calculated in accordance 

with paragraph (d)(10) of this section. 

Vs,RF = Standardized volume of the batch of 

renewable fuel at 60 °F that must be 

assigned a D code of 4 based on its fuel 

type, in gallons, calculated in accordance 

with paragraph (d)(10) of this section. 

(v) If a producer produces a single 

type of renewable fuel using two or 

more different feedstocks which are 

processed simultaneously, then the 

number of gallon-RINs that shall be 

generated for each batch of renewable 

fuel and assigned a particular D code 

shall be determined according to the 

formulas in Table 3 to this section. 

Where: 

VRIN,CB = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for a batch of 

cellulosic biofuel with a D code of 1. 

VRIN,BBD = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for a batch of 

biomass-based diesel with a D code of 2. 

VRIN,AB = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for a batch of 

advanced biofuel with a D code of 3. 

VRIN,RF = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for a batch of 

renewable fuel with a D code of 4. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

FE1 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 1 under Table 1 to this section, 

in Btu. 

FE2 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 2 under Table 1 to this section, 

in Btu. 

FE3 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 3 under Table 1 to this section, 

in Btu. 

FE4 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 


EP26MY09.018</GPH>
Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25121 

code of 4 under Table 1 to this section, 

in Btu. 

Feedstock energy values, FE, shall be 

calculated according to the following 

formula: 

FE = M * CF * E 

Where: 

FE = Feedstock energy, in Btu. 

M = Mass of feedstock, in pounds. 

CF = Converted Fraction in annual average 

mass percent, representing that portion 

of the feedstock that is estimated to be 

converted into renewable fuel by the 

producer. 

E = Energy content of the fuel precursor 

fraction for the feedstock in annual 

average Btu/lb. 

(6) Producers who co-process 

renewable biomass and fossil fuels 

simultaneously to produce a 

transportation fuel that is partially 

renewable. (i) The number of gallonRINs that shall be generated for a given 

batch of partially renewable 

transportation fuel shall be equal to a 

volume calculated according to the 

following formula: 

VRIN = EV * Vs * FER/(FER + FEF) 

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

FER = Feedstock energy from renewable 

biomass used to make the transportation 

fuel, in Btu. 

FEF = Feedstock energy from fossil fuel used 

to make the transportation fuel, in Btu. 

(ii) The value of FE for use in 

paragraph (d)(6)(i) of this section shall 

be calculated from the following 

formula: 

FE = M * CF * E 

Where: 

FE = Feedstock energy, in Btu. 

M = Mass of feedstock, in pounds. 

CF = Converted Fraction in annual average 

mass percent, representing that portion 

of the feedstock that is estimated to be 

converted into transportation fuel by the 

producer. 

E = Energy content of the fuel precursor 

fraction for the feedstock, in annual 

average Btu/lb. 

(iii) The D code that shall be used in 

the RINs generated to represent partially 

renewable transportation fuel shall be 

the D code specified in Table 1 to this 

section which corresponds to the 

pathway that describes a producer’s 

operations. In determining the 

appropriate pathway, the contribution 

of fossil fuel feedstocks to the 

production of partially renewable fuel 

shall be ignored. 

(7) Producers without an applicable 

pathway. (i) If none of the pathways 

described in Table 1 to this section 

apply to a producer’s operations, a party 

generating a RIN may nevertheless use 

a pathway in Table 1 to this section if 

EPA allows the use of a temporary D 

code pursuant to § 80.1416(c). 

(ii) If none of the pathways described 

in Table 1 to this section apply to a 

producer’s operations and the party 

generating the RIN does not qualify to 

use a temporary D code according to the 

provisions of § 80.1416(c), the party 

must generate RINs if the fuel from its 

facility qualifies for grandfathering as 

provided in § 80.1403. 

(A) The number of gallon-RINs that 

shall be generated for a given batch of 

grandfathered renewable fuel shall be 

equal to a volume calculated according 

to the following formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60°F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

(B) A D code of 4 shall be used in the 

RINs generated under paragraph 

(d)(7)(ii)(A) of this section. 

(8) Provisions for importers of 

renewable fuel. (i) The number of 

gallon-RINs that shall be generated for a 

given batch of renewable fuel shall be 

equal to a volume calculated according 

to the following formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated. 

EV = Equivalence value for the renewable 

fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(d)(10) of this section. 

(ii) The D code that shall be used in 

the RINs generated by an importer of 

renewable fuel shall be determined from 

information provided by the foreign 

producer specifying the applicable 

pathway or pathways for the renewable 

fuel and the provisions of this paragraph 

(d). 

(9) Multiple gallon-RINs generated to 

represent a given volume of renewable 

fuel can be represented by a single 

batch-RIN through the appropriate 

designation of the RIN volume codes 

SSSSSSSS and EEEEEEEE. 

(i) The value of SSSSSSSS in the 

batch-RIN shall be 00000001 to 

represent the first gallon-RIN associated 

with the volume of renewable fuel. 

(ii) The value of EEEEEEEE in the 

batch-RIN shall represent the last 

gallon-RIN associated with the volume 

of renewable fuel, based on the RIN 

volume determined pursuant to 

paragraph (d)(4) of this section. 

(10) Standardization of volumes. In 

determining the standardized volume of 

a batch of renewable fuel for purposes 

of generating RINs under this paragraph 

(d), the batch volumes shall be adjusted 

to a standard temperature of 60 °F. 

(i) For ethanol, the following formula 

shall be used: 

Vs,e = Va,e * (¥0.0006301 * T + 1.0378) 

Where: 

Vs,e = Standardized volume of ethanol at 60 

°F, in gallons. 

Va,e = Actual volume of ethanol, in gallons. 

T = Actual temperature of the batch, in °F. 

(ii) For biodiesel (mono-alkyl esters), 

the following formula shall be used: 

Vs,b = Va,b * (¥0.0008008 * T + 1.0480) 

Where: 

Vs,b = Standardized volume of biodiesel at 60 

°F, in gallons. 

Va,b = Actual volume of biodiesel, in gallons. 

T = Actual temperature of the batch, in °F. 

(iii) For other renewable fuels, an 

appropriate formula commonly 

accepted by the industry shall be used 

to standardize the actual volume to 60 

°F. Formulas used must be reported to 

EPA, and may be reviewed for 

appropriateness. 

(11)(i) A party is prohibited from 

generating RINs for a volume of fuel that 

it produces if: 

(A) The fuel has been produced from 

a chemical conversion process that uses 

another renewable fuel as a feedstock, 

and the renewable fuel used as a 

feedstock was produced by another 

party; or 

(B) The fuel is not produced from 

renewable biomass. 

(ii) Parties who produce renewable 

fuel made from a feedstock which itself 

was a renewable fuel with RINs, shall 

assign the original RINs to the new 

renewable fuel. 

(e) Assignment of RINs to batches. (1) 

The producer or importer of renewable 

fuel must assign all RINs generated to 

volumes of renewable fuel. 

(2) A RIN is assigned to a volume of 

renewable fuel when ownership of the 

RIN is transferred along with the 

transfer of ownership of the volume of 

renewable fuel, pursuant to § 80.1428(a). 

(3) All assigned RINs shall have a K 

code value of 1. 

(4) Any RINs generated but not 

assigned to a volume of renewable fuel 

must be counted with assigned RINs in 

25122 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

the quarterly RIN and volume inventory 

balance check calculation required in 

§ 80.1428. 

§ 80.1427 How are RINs used to 

demonstrate compliance? 

(a) Renewable Volume Obligations. (1) 

Except as specified in paragraph (b) of 

this section or § 80.1455, each party that 

is obligated to meet the Renewable 

Volume Obligations under § 80.1407, or 

each party that is an exporter of 

renewable fuels that is obligated to meet 

Renewable Volume Obligations under 

§ 80.1430, must demonstrate pursuant to 

§ 80.1452(a)(1) that it owns sufficient 

RINs to satisfy the following equations: 

(i) Cellulosic biofuel. 

(SRINNUM)CB,i + (SRINNUM)CB,i¥1 = 

RVOCB,i

Where: 

(SRINNUM)CB,i = Sum of all owned gallonRINs that are valid for use in complying 

with the cellulosic biofuel RVO, were 

generated in year i, and are being applied 

towards the RVOCB,i, in gallons. 

(SRINNUM)CB,i¥1 = Sum of all owned gallonRINs that are valid for use in complying 

with the cellulosic biofuel RVO, were 

generated in year i¥1, and are being 

applied towards the RVOCB,i, in gallons. 

RVOCB,i = The Renewable Volume Obligation 

for cellulosic biofuel for the obligated 

party or renewable fuel exporter for 

calendar year i, in gallons, pursuant to 

§ 80.1407 or § 80.1430. 

(ii) Biomass-based diesel. 

(SRINNUM)BBD,i + (SRINNUM)BBD,i¥1 = 

RVOBBD,i

Where: 

(SRINNUM)BBD,i = Sum of all owned gallonRINs that are valid for use in complying 

with the biomass-based diesel RVO, were 

generated in year i, and are being applied 

towards the RVOBBD,i, in gallons. 

(SRINNUM)BBD,i¥1 = Sum of all owned 

gallon-RINs that are valid for use in 

complying with the biomass-based diesel 

RVO, were generated in year i¥1, and 

are being applied towards the RVOBBD,i, 

in gallons. 

RVOBBD,i = The Renewable Volume 

Obligation for biomass-based diesel for 

the obligated party or renewable fuel 

exporter for calendar year i after 2010, in 

gallons, pursuant to § 80.1407 or 

§ 80.1430. 

(iii) Advanced biofuel. 

(SRINNUM)AB,i + (SRINNUM)AB,i¥1 = 

RVOAB,i

Where: 

(SRINNUM)AB,i = Sum of all owned gallonRINs that are valid for use in complying 

with the advanced biofuel RVO, were 

generated in year i, and are being applied 

towards the RVOAB,i, in gallons. 

(SRINNUM)AB,i¥1 = Sum of all owned gallonRINs that are valid for use in complying 

with the advanced biofuel RVO, were 

generated in year i¥1, and are being 

applied towards the RVOAB,i, in gallons. 

RVOAB,i = The Renewable Volume Obligation 

for advanced biofuel for the obligated 

party or renewable fuel exporter for 

calendar year i, in gallons, pursuant to 

§ 80.1407 or § 80.1430. 

(iv) Renewable fuel. 

(SRINNUM)RF,i + (SRINNUM)RF,i¥1 = 

RVORF,i

Where: 

(SRINNUM)RF,i = Sum of all owned gallonRINs that are valid for use in complying 

with the renewable fuel RVO, were 

generated in year i, and are being applied 

towards the RVORF,i, in gallons. 

(SRINNUM)RF,i¥1 = Sum of all owned gallonRINs that are valid for use in complying 

with the renewable fuel RVO, were 

generated in year i¥1, and are being 

applied towards the RVORF,i, in gallons. 

RVORF,i = The Renewable Volume Obligation 

for renewable fuel for the obligated party 

or renewable fuel exporter for calendar 

year i, in gallons, pursuant to § 80.1407 

or § 80.1430. 

(2) Except as described in paragraph 

(a)(3) of this section, RINs that are valid 

for use in complying with each 

Renewable Volume Obligation are 

determined by their D codes. 

(i) RINs with a D code of 1 are valid 

for compliance with the cellulosic 

biofuel RVO. 

(ii) RINs with a D code of 2 are valid 

for compliance with the biomass-based 

diesel RVO. 

(iii) RINs with a D code of 1, 2, or 3 

are valid for compliance with the 

advanced biofuel RVO. 

(iv) RINs with a D code of 1, 2, 3, or 

4 are valid for compliance with the 

renewable fuel RVO. 

(3) For purposes of demonstrating 

compliance for calendar year 2010, RINs 

generated in 2009 pursuant to § 80.1126 

that are not used for compliance 

purposes for calendar year 2009 may be 

used for compliance in 2010, insofar as 

permissible pursuant to paragraphs 

(a)(5) and (a)(7)(iv) of this section, as 

follows: 

(i) A 2009 RIN with an RR code of 15 

or 17 is deemed equivalent to a RIN 

generated pursuant to § 80.1426 having 

a D code of 2. 

(ii) A 2009 RIN with a D code of 1 is 

deemed equivalent to a RIN generated 

pursuant to § 80.1426 having a D code 

of 1. 

(iii) All other 2009 RINs are deemed 

equivalent to RINs generated pursuant 

to § 80.1426 having D codes of 4. 

(iv) A 2009 RIN that is retired 

pursuant to § 80.1129(e) because the 

associated volume of fuel is not used as 

motor vehicle fuel may be reinstated 

pursuant to § 80.1429(f)(1). 

(4) A party may use the same RIN to 

demonstrate compliance with more than 

one RVO so long as it is valid for 

compliance with all RVOs to which it is 

applied. 

(5) Except as provided in paragraph 

(a)(7)(iv) of this section, the value of 

(SRINNUM)i–1 may not exceed values 

determined by the following 

inequalities: 

(SRINNUM)CB,i–1 ≤ 0.20 * RVOCB,i

(SRINNUM)BBD,i–1 ≤ 0.20 * RVOBBD,i

(SRINNUM)AB,i–1 ≤ 0.20 * RVOAB,i

(SRINNUM)RF,i–1 ≤ 0.20 * RVORF,i

(6) Except as provided in paragraphs 

(a)(7)(ii) and (iii) of this section, RINs 

may only be used to demonstrate 

compliance with the RVOs for the 

calendar year in which they were 

generated or the following calendar 

year. RINs used to demonstrate 

compliance in one year cannot be used 

to demonstrate compliance in any other 

year. 

(7) Biomass-based diesel in 2010. (i) 

Prior to determining compliance with 

the 2010 biomass-based diesel RVO, 

obligated parties may reduce the value 

of RVOBBD,2010 by an amount equal to 

the sum of all 2008 and 2009 RINs used 

for compliance purposes for calendar 

year 2009 which have an RR code of 15 

or 17. 

(ii) For calendar year 2010 only, the 

following equation shall be used to 

determine compliance with the 

biomass-based diesel RVO instead of the 

equation in paragraph (a)(1)(ii) of this 

section: 

(SRINNUM)BBD,2010 + 

(SRINNUM)BBD,2009 + 

(SRINNUM)BBD,2008 = RVOBBD,2010

Where: 

(SRINNUM)BBD,2010 = Sum of all owned 

gallon-RINs that are valid for use in 

complying with the biomass-based diesel 

RVO, were generated in year 2010, and 

are being applied towards the 

RVOBBD,2010, in gallons. 

(SRINNUM)BBD,2009 = Sum of all owned 

gallon-RINs that are valid for use in 

complying with the biomass-based diesel 

RVO, were generated in year 2009, have 

not previously been used for compliance 

purposes, and are being applied towards 

the RVOBBD,2010, in gallons. 

(SRINNUM)BBD,2008 = Sum of all owned 

gallon-RINs that are valid for use in 

complying with the biomass-based diesel 

RVO, were generated in year 2008, have 

not previously been used for compliance 

purposes, and are being applied towards 

the RVOBBD,2010, in gallons. 

RVOBBD,2010 = The Renewable Volume 

Obligation for biomass-based diesel for 

the obligated party or renewable fuel 

exporter for calendar year 2010, in 

gallons, pursuant to § 80.1407 or 

§ 80.1430, as adjusted by paragraph 

(a)(7)(i) of this section. 

(iii) RINs generated in 2008 or 2009 

which have not been used for 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25123 

compliance purposes for calendar years 

2008 or 2009 and which have an RR 

code of 15 or 17 may be used to 

demonstrate compliance with the 2010 

biomass-based diesel RVO. 

(iv) For compliance with the biomassbased diesel RVO in calendar year 2010 

only, the values of (SRINNUM)2008 and 

(SRINNUM)2009 may not exceed values 

determined by both of the following 

inequalities: 

(SRINNUM)BBD,2008 ≤ 0.087 * 

RVOBBD,2010

(SRINNUM)BBD,2008 + 

(SRINNUM)BBD,2009 ≤ 0.20 * RVOBBD,2010

(8) A party may only use a RIN for 

purposes of meeting the requirements of 

paragraph (a)(1) of this section if that 

RIN is a separated RIN with a K code of 

2 obtained in accordance with 

§§ 80.1428 and 80.1429. 

(9) The number of gallon-RINs 

associated with a given batch-RIN that 

can be used for compliance with the 

RVOs shall be calculated from the 

following formula: 

RINNUM = EEEEEEEE¥SSSSSSSS + 1 

Where: 

RINNUM = Number of gallon-RINs associated 

with a batch-RIN, where each gallon-RIN 

represents one gallon of renewable fuel 

for compliance purposes. 

EEEEEEEE = Batch-RIN component 

identifying the last gallon-RIN associated 

with the batch-RIN. 

SSSSSSSS = Batch-RIN component 

identifying the first gallon-RIN 

associated with the batch-RIN. 

(b) Deficit carryovers. (1) An obligated 

party or an exporter of renewable fuel 

that fails to meet the requirements of 

paragraph (a)(1) or (a)(5) of this section 

for calendar year i is permitted to carry 

a deficit into year i+1 under the 

following conditions: 

(i) The party did not carry a deficit 

into calendar year i from calendar year 

i¥1 for the same RVO. 

(ii) The party subsequently meets the 

requirements of paragraph (a)(1) of this 

section for calendar year i+1 and carries 

no deficit into year i+2 for the same 

RVO. 

(iii) For compliance with the biomassbased diesel RVO in calendar year 2011, 

the deficit which is carried over from 

2010 is no larger than 57% of the party’s 

2010 biomass-based diesel RVO as 

determined prior to any adjustment 

applied pursuant to paragraph (a)(7)(i) 

of this section. 

(2) A deficit is calculated according to 

the following formula: 

Di = RVOi¥[(SRINNUM)i + 

(SRINNUM)i¥1] 

Where: 

Di = The deficit, in gallons, generated in 

calendar year i that must be carried over 

to year i+1 if allowed to do so pursuant 

to paragraph (b)(1) of this section. 

RVOi = The Renewable Volume Obligation 

for the obligated party or renewable fuel 

exporter for calendar year i, in gallons. 

(ΣRINNUM)i = Sum of all acquired gallonRINs that were generated in year i and are 

being applied towards the RVOi, in gallons. 

(ΣRINNUM)i¥1 = Sum of all acquired 

gallon-RINs that were generated in year i-1 

and are being applied towards the RVOi, in 

gallons. 

§ 80.1428 General requirements for RIN 

distribution. 

(a) RINs assigned to volumes of 

renewable fuel and RINs generated, but 

not assigned. (1) Definitions. (i) 

Assigned RIN, for the purposes of this 

subpart, means a RIN assigned to a 

volume of renewable fuel pursuant to 

§ 80.1426(e) with a K code of 1. 

(ii) RINS generated, but not assigned 

are those RINs that have been generated 

pursuant to 80.1426(a), but have not 

been assigned to a volume of renewable 

fuel pursuant to 80.1426(e). 

(2) Except as provided in § 80.1429, 

no party can separate a RIN that has 

been assigned to a batch pursuant to 

§ 80.1426(e). 

(3) An assigned RIN cannot be 

transferred to another party without 

simultaneously transferring a volume of 

renewable fuel to that same party. 

(4) No more than 2.5 assigned gallonRINs with a K code of 1 can be 

transferred to another party with every 

gallon of renewable fuel transferred to 

that same party. 

(5)(i) On each of the dates listed in 

paragraph (a)(5)(ii) of this section in any 

calendar year, the following equation 

must be satisfied for assigned RINs and 

volumes of renewable fuel owned by a 

party: 

Σ(RIN)D ≤ Σ(Vsi * 2.5)D

Where: 

D = Applicable date. 

Σ(RIN)D = Sum of all assigned gallon-RINs 

with a K code of 1 and all RINs 

generated, but not assigned that are 

owned on date D. 

(Vsi)D = Volume i of renewable fuel owned on 

date D, standardized to 60 °F, in gallons. 

Σ(Vsi * 2.5)D = Sum of all volumes of 

renewable fuel owned on date D, 

multiplied by an equivalence value of 

2.5. 

(ii) The applicable dates are March 31, 

June 30, September 30, and December 

31. 

(6) Any transfer of ownership of 

assigned RINs must be documented on 

product transfer documents generated 

pursuant to § 80.1453. 

(i) The RIN must be recorded on the 

product transfer document used to 

transfer ownership of the volume of 

renewable fuel to another party; or 

(ii) The RIN must be recorded on a 

separate product transfer document 

transferred to the same party on the 

same day as the product transfer 

document used to transfer ownership of 

the volume of renewable fuel. 

(b) RINs separated from volumes of 

renewable fuel. (1) Separated RIN, for 

the purposes of this subpart, means a 

RIN with a K code of 2 that has been 

separated from a volume of renewable 

fuel pursuant to § 80.1429. 

(2) Any party that has registered 

pursuant to § 80.1450 can hold title to 

a separated RIN. 

(3) Separated RINs can be transferred 

from one party to another any number 

of times. 

(c) RIN expiration. A RIN is valid for 

compliance during the year in which it 

was generated, or the following year. 

Any RIN that is not used for compliance 

purposes during the year that it was 

generated, or during the following year, 

will be considered an expired RIN. 

Pursuant to § 80.1431(a)(3), an expired 

RIN that is used for compliance will be 

considered an invalid RIN. 

(d) Any batch-RIN can be divided by 

its owner into multiple batch-RINs, each 

representing a smaller number of gallonRINs, if all of the following conditions 

are met: 

(1) All RIN components other than 

SSSSSSSS and EEEEEEEE are identical 

for the original parent and newly 

formed daughter RINs. 

(2) The sum of the gallon-RINs 

associated with the multiple daughter 

batch-RINs is equal to the gallon-RINs 

associated with the parent batch-RIN. 

§ 80.1429 Requirements for separating 

RINs from volumes of renewable fuel. 

(a)(1) Separation of a RIN from a 

volume of renewable fuel means 

termination of the assignment of the RIN 

to a volume of renewable fuel. 

(2) RINs that have been separated 

from volumes of renewable fuel become 

separated RINs subject to the provisions 

of § 80.1428(b). 

(b) A RIN that is assigned to a volume 

of renewable fuel is separated from that 

volume only under one of the following 

conditions: 

(1) Except as provided in paragraph 

(b)(6) of this section, a party that is an 

obligated party according to § 80.1406 

must separate any RINs that have been 

assigned to a volume of renewable fuel 

if they own that volume. 

(2) Except as provided in paragraph 

(b)(5) of this section, any party that 

owns a volume of renewable fuel must 

separate any RINs that have been 

assigned to that volume once the 

volume is blended with gasoline or 

diesel to produce a transportation fuel, 

25124 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

home heating oil, or jet fuel. A party 

may separate up to 2.5 RINs per gallon 

of renewable fuel. 

(3) Any party that exports a volume of 

renewable fuel must separate any RINs 

that have been assigned to the exported 

volume. 

(4) Any party that produces, imports, 

owns, sells, or uses a volume of neat 

renewable fuel, or a blend of renewable 

fuel and diesel fuel, must separate any 

RINs that have been assigned to that 

volume of neat renewable fuel or that 

blend if: 

(i) The party designates the neat 

renewable fuel or blend as 

transportation fuel, home heating oil, or 

jet fuel: and 

(ii) The neat renewable fuel or blend 

is used without further blending, in the 

designated form, as transportation fuel, 

home heating oil, or jet fuel. 

(5) RINs assigned to a volume of 

biodiesel (mono-alkyl ester) can only be 

separated from that volume pursuant to 

paragraph (b)(2) of this section if such 

biodiesel is blended into diesel fuel at 

a concentration of 80 volume percent 

biodiesel (mono-alkyl ester) or less. 

(i) This paragraph (b)(5) shall not 

apply to obligated parties or exporters of 

renewable fuel. 

(ii) This paragraph (b)(5) shall not 

apply to parties meeting the 

requirements of paragraph (b)(4) of this 

section. 

(6) For RINs that an obligated party 

generates for renewable fuel that has not 

been blended into gasoline or diesel to 

produce a transportation fuel, the 

obligated party can only separate such 

RINs from volumes of renewable fuel if 

the number of gallon-RINs separated in 

a calendar year is less than or equal to 

a limit set as follows: 

(i) For RINs with a D code of 1, the 

limit shall be equal to RVOCB. 

(ii) For RINs with a D code of 2, the 

limit shall be equal to RVOBBD. 

(iii) For RINs with a D code of 3, the 

limit shall be equal to RVOAB — 

RVOCB—RVOBBD.

(iv) For RINs with a D code of 4, the 

limit shall be equal to RVORF — RVOAB. 

(7) For a party that has received a 

small refinery exemption under 

§ 80.1441 or a small refiner exemption 

under § 80.1442, and is not otherwise an 

obligated party, during the period of 

time that the small refinery or small 

refiner exemptions are in effect, the 

party may only separate RINs that have 

been assigned to volumes of renewable 

fuel that the party blends into gasoline 

or diesel to produce transportation fuel, 

or that the party used as home heating 

oil or jet fuel. 

(c) The party responsible for 

separating a RIN from a volume of 

renewable fuel shall change the K code 

in the RIN from a value of 1 to a value 

of 2 prior to transferring the RIN to any 

other party. 

(d) Upon and after separation of a RIN 

from its associated volume of renewable 

fuel, the separated RIN must be 

accompanied by documentation when 

transferred. 

(1) When transferred, the separated 

RIN shall appear on documentation that 

includes all the following information: 

(i) The name and address of the 

transferor and transferee. 

(ii) The transferor’s and transferee’s 

EPA company registration numbers. 

(iii) The date of the transfer. 

(iv) A list of separated RINs 

transferred. 

(2) [Reserved] 

(e) Upon and after separation of a RIN 

from its associated volume of renewable 

fuel, product transfer documents used to 

transfer ownership of the volume must 

continue to meet the requirements of 

§ 80.1453(a)(5)(iii). 

(f) Any party that uses a renewable 

fuel in a commercial or industrial boiler 

or ocean-going vessel (as defined in 

§ 80.1401), or designates a renewable 

fuel for use in a boiler or ocean-going 

vessel, must retire any RINs received 

with that renewable fuel and report the 

retired RINs in the applicable reports 

under § 80.1452. Any 2009 RINs retired 

pursuant to § 80.1129(e) may be 

reinstated by the retiring party for sale 

or use to demonstrate compliance with 

a 2010 RVO. 

§ 80.1430 Requirements for exporters of 

renewable fuels. 

(a) Any party that owns any amount 

of renewable fuel, whether in its neat 

form or blended with gasoline or diesel, 

that is exported from any of the regions 

described in § 80.1426(a) shall acquire 

sufficient RINs to offset all applicable 

Renewable Volume Obligations 

representing the exported renewable 

fuel. 

(b) Renewable Volume Obligations. 

An exporter of renewable fuel shall 

determine its Renewable Volume 

Obligations from the volumes of the 

renewable fuel exported. 

(1) For exported volumes of biodiesel 

(mono-alkyl ester) or non-ester 

renewable diesel, a renewable fuel 

exporter’s Renewable Volume 

Obligation for biomass-based diesel 

shall be calculated according to the 

following formula: 

RVOBBD,i = S(VOLk * EVk)i + DBBD,i-1

Where: 

RVOBBD,i = The Renewable Volume 

Obligation for biomass-based diesel for 

the exporter for calendar year i, in 

gallons. 

k = A discrete volume of biodiesel (monoalkyl ester) or non-ester renewable diesel 

fuel. 

VOLk = The standardized volume of discrete 

volume k of exported biodiesel (monoalkyl ester) or non-ester renewable 

diesel, in gallons, calculated in 

accordance with § 80.1426(d)(10). 

EVk = The equivalence value associated with 

discrete volume k. 

S = Sum involving all volumes of biodiesel 

(mono-alkyl ester) or non-ester 

renewable diesel exported. 

DBBD,i-1 = Deficit carryover from the previous 

year for biomass-based diesel, in gallons. 

(2) For exported volumes of all 

renewable fuels, a renewable fuel 

exporter’s Renewable Volume 

Obligation for total renewable fuel shall 

be calculated according to the following 

formula: 

RVORF,i = S(VOLk * EVk)i + DRF,i-1

Where: 

RVORF,i = The Renewable Volume Obligation 

for renewable fuel for the exporter for 

calendar year i, in gallons of renewable 

fuel. 

k = A discrete volume of renewable fuel. 

VOLk = The standardized volume of discrete 

volume k of exported renewable fuel, in 

gallons, calculated in accordance with 

§ 80.1426(d)(10). 

EVk = The equivalence value associated with 

discrete volume k. 

S = Sum involving all volumes of renewable 

fuel exported. 

DRF,i-1 = Deficit carryover from the previous 

year for renewable fuel, in gallons. 

(3)(i) If the equivalence value for a 

volume of renewable fuel can be 

determined pursuant to § 80.1415 based 

on its composition, then the appropriate 

equivalence value shall be used in the 

calculation of the exporter’s Renewable 

Volume Obligations. 

(ii) If the equivalence value for a 

volume of renewable fuel cannot be 

determined, the value of EVk shall be 

1.0. 

(c) Each exporter of renewable fuel 

must demonstrate compliance with its 

RVOs using RINs it has acquired, 

pursuant to § 80.1427. 

§ 80.1431 Treatment of invalid RINs. 

(a) Invalid RINs. An invalid RIN is a 

RIN that is any of the following: 

(1) Is a duplicate of a valid RIN. 

(2) Was based on volumes that have 

not been standardized to 60 °F. 

(3) Has expired, except as provided in 

§ 80.1428(c). 

(4) Was based on an incorrect 

equivalence value. 

(5) Is deemed invalid under 

§ 80.1467(g). 

(6) Does not represent renewable fuel 

as defined in § 80.1401. 

(7) Was assigned an incorrect ‘‘D’’ 

code value under § 80.1426(d)(3) for the 

associated volume of fuel. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25125 

(8) In the event that the same RIN is 

transferred to two or more parties, all 

such RINs are deemed invalid, unless 

EPA in its sole discretion determines 

that some portion of these RINs is valid. 

(9) Was otherwise improperly 

generated. 

(b) In the case of RINs that are invalid, 

the following provisions apply: 

(1) Upon determination by any party 

that RINs owned are invalid, the party 

must adjust its records, reports, and 

compliance calculations in which the 

invalid RINs were used as necessary to 

reflect the deletion of the invalid RINs. 

The party must retire the invalid RINs 

in the applicable RIN transaction reports 

under § 80.1452(c)(2) for the quarter in 

which the RINs were determined to be 

invalid. 

(2) Invalid RINs cannot be used to 

achieve compliance with the Renewable 

Volume Obligations of an obligated 

party or exporter, regardless of the 

party’s good faith belief that the RINs 

were valid at the time they were 

acquired. 

(3) Any valid RINs remaining after 

deleting invalid RINs must first be 

applied to correct the transfer of invalid 

RINs to another party before applying 

the valid RINs to meet the party’s 

Renewable Volume Obligations at the 

end of the compliance year. 

§ 80.1432 Reported spillage or disposal of 

renewable fuel. 

(a) A reported spillage or disposal 

under this subpart means a spillage or 

disposal of renewable fuel associated 

with a requirement by a federal, state, or 

local authority to report the spillage or 

disposal. 

(b) Except as provided in paragraph 

(c) of this section, in the event of a 

reported spillage or disposal of any 

volume of renewable fuel, the owner of 

the renewable fuel must retire a number 

of RINs corresponding to the volume of 

spilled or disposed of renewable fuel 

multiplied by its equivalence value. 

(1) If the equivalence value for the 

spilled or disposed of volume may be 

determined pursuant to § 80.1415 based 

on its composition, then the appropriate 

equivalence value shall be used. 

(2) If the equivalence value for a 

spilled or disposed of volume of 

renewable fuel cannot be determined, 

the equivalence value shall be 1.0. 

(c) If the owner of a volume of 

renewable fuel that is spilled or 

disposed of and reported establishes 

that no RINs were generated to represent 

the volume, then no RINs shall be 

retired. 

(d) A RIN that is retired under 

paragraph (b) of this section: 

(1) Must be reported as a retired RIN 

in the applicable reports under 

§ 80.1452. 

(2) May not be transferred to another 

party or used by any obligated party to 

demonstrate compliance with the 

party’s Renewable Volume Obligations. 

§§ 80.1433–80.1439 [Reserved] 

§ 80.1440 What are the provisions for 

blenders who handle and blend less than 

125,000 gallons of renewable fuel per year? 

(a) Renewable fuel blenders who 

handle and blend less than 125,000 

gallons of renewable fuel per year, and 

who do not have Renewable Volume 

Obligations, are permitted to delegate 

their RIN-related responsibilities to the 

party directly upstream of them who 

supplied the renewable fuel for 

blending. 

(b) The RIN-related responsibilities 

that may be delegated directly upstream 

include all the following: 

(1) The RIN separation requirements 

of § 80.1429. 

(2) The recordkeeping requirements of 

§ 80.1451. 

(3) The reporting requirements of 

§ 80.1452. 

(4) The attest engagement 

requirements of § 80.1464. 

(c) For upstream delegation of RINrelated responsibilities, both parties 

must agree on the delegation, and a 

quarterly written statement signed by 

both parties must be included with the 

reporting party’s reports under 

§ 80.1452. 

(1) If EPA finds that a renewable fuel 

blender improperly delegated its RINrelated responsibilities under this 

subpart M, the blender will be held 

accountable for any RINs separated and 

will be subject to all RIN-related 

responsibilities under this subpart. 

(2) [Reserved] 

(d) Renewable fuel blenders who 

handle and blend less than 125,000 

gallons of renewable fuel per year and 

who do not opt to delegate their RINrelated responsibilities will be subject to 

all requirements stated in paragraph (b) 

of this section, and all other applicable 

requirements of this subpart M. 

§ 80.1441 Small refinery exemption. 

(a)(1) Transportation fuel produced at 

a refinery by a refiner, or foreign refiner 

(as defined at § 80.1465(a)), is exempt 

through December 31, 2010 from the 

renewable fuel standards of § 80.1405; 

and the refinery, or foreign refinery, is 

exempt from the requirements that 

apply to obligated parties under this 

subpart M if that refinery meets the 

definition of a small refinery under 

§ 80.1401 for calendar year 2006. 

(2) This exemption shall apply unless 

a refiner chooses to waive this 

exemption (as described in paragraph (f) 

of this section), or the exemption is 

extended (as described in paragraph (e) 

of this section). 

(3) For the purposes of this section, 

the term ‘‘refiner’’ shall include foreign 

refiners. 

(4) This exemption shall only apply to 

refineries that process crude oil through 

refinery processing units. 

(5) The small refinery exemption is 

effective immediately, except as 

specified in paragraph (b)(3) of this 

section. 

(b)(1) A refiner owning a small 

refinery must submit a verification letter 

to EPA containing all of the following 

information: 

(i) The annual average aggregate daily 

crude oil throughput for the period 

January 1, 2006 through December 31, 

2006 (as determined by dividing the 

aggregate throughput for the calendar 

year by the number 365). 

(ii) A letter signed by the president, 

chief operating or chief executive officer 

of the company, or his/her designee, 

stating that the information contained in 

the letter is true to the best of his/her 

knowledge, and that the refinery was 

small as of December 31, 2006. 

(iii) Name, address, phone number, 

facsimile number, and e-mail address of 

a corporate contact person. 

(2) Verification letters must be 

submitted by January 1, 2010 to one of 

the addresses listed in paragraph (h) of 

this section. 

(3) For foreign refiners the small 

refinery exemption shall be effective 

upon approval, by EPA, of a small 

refinery application. The application 

must contain all of the elements 

required for small refinery verification 

letters (as specified in paragraph (b)(1) 

of this section), must satisfy the 

provisions of § 80.1465(f) through (h) 

and (o), and must be submitted by 

January 1, 2010 to one of the addresses 

listed in paragraph (h) of this section. 

(4) Small refinery verification letters 

are not required for those refiners who 

have already submitted a verification 

letter under subpart K of this Part 80. 

(c) If EPA finds that a refiner provided 

false or inaccurate information 

regarding a refinery’s crude throughput 

(pursuant to paragraph (b)(1)(i) of this 

section) in its small refinery verification 

letter, the exemption will be void as of 

the effective date of these regulations. 

(d) If a refiner is complying on an 

aggregate basis for multiple refineries, 

any such refiner may exclude from the 

calculation of its Renewable Volume 

Obligations (under § 80.1407) 

transportation fuel from any refinery 

25126 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

receiving the small refinery exemption 

under paragraph (a) of this section. 

(e)(1) The exemption period in 

paragraph (a) of this section shall be 

extended by the Administrator for a 

period of not less than two additional 

years if a study by the Secretary of 

Energy determines that compliance with 

the requirements of this subpart would 

impose a disproportionate economic 

hardship on a small refinery. 

(2) A refiner may petition the 

Administrator for an extension of its 

small refinery exemption, based on 

disproportionate economic hardship, at 

any time. 

(i) A petition for an extension of the 

small refinery exemption must specify 

the factors that demonstrate a 

disproportionate economic hardship 

and must provide a detailed discussion 

regarding the hardship the refinery 

would face in producing transportation 

fuel meeting the requirements of 

§ 80.1405 and the date the refiner 

anticipates that compliance with the 

requirements can reasonably be 

achieved at the small refinery. 

(ii) The Administrator shall act on 

such a petition not later than 90 days 

after the date of receipt of the petition. 

(f) At any time, a refiner with an 

approved small refinery exemption 

under paragraph (a) of this section may 

waive that exemption upon notification 

to EPA. 

(1) A refiner’s notice to EPA that it 

intends to waive its small refinery 

exemption must be received by 

November 1 to be effective in the next 

compliance year. 

(2) The waiver will be effective 

beginning on January 1 of the following 

calendar year, at which point the 

gasoline produced at that refinery will 

be subject to the renewable fuels 

standard of § 80.1405 and all other 

requirements that apply to obligated 

parties under this Subpart M. 

(3) The waiver must be sent to EPA 

at one of the addresses listed in 

paragraph (h) of this section. 

(g) A refiner that acquires a refinery 

from either an approved small refiner 

(as defined under § 80.1442(a)) or 

another refiner with an approved small 

refinery exemption under paragraph (a) 

of this section shall notify EPA in 

writing no later than 20 days following 

the acquisition. 

(h) Verification letters under 

paragraph (b) of this section, petitions 

for small refinery hardship extensions 

under paragraph (e) of this section, and 

small refinery exemption waivers under 

paragraph (f) of this section shall be sent 

to one of the following addresses: 

(1) For US mail: U.S. EPA, Attn: RFS2 

Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS2 Program, 6406J, 

1310 L Street, NW, 6th floor, 

Washington, DC 20005. (202) 343–9038. 

§ 80.1442 What are the provisions for 

small refiners under the RFS program? 

(a)(1) To qualify as a small refiner 

under this section, a refiner must meet 

all of the following criteria: 

(i) The refiner produced 

transportation fuel at its refineries by 

processing crude oil through refinery 

processing units from January 1, 2006 

through December 31, 2006. 

(ii) The refiner employed an average 

of no more than 1,500 people, based on 

the average number of employees for all 

pay periods for calendar year 2006 for 

all subsidiary companies, all parent 

companies, all subsidiaries of the parent 

companies, and all joint venture 

partners. 

(iii) The refiner had a corporateaverage crude oil capacity less than or 

equal to 155,000 barrels per calendar 

day (bpcd) for 2006. 

(2) For the purposes of this section, 

the term ‘‘refiner’’ shall include foreign 

refiners. 

(b) Applications for small refiner 

status. (1) Applications for small refiner 

status under this section must be 

submitted to EPA by January 1, 2010. 

(2) Small refiner status applications 

under this section must include all the 

following information for the refiner 

and for all subsidiary companies, all 

parent companies, all subsidiaries of the 

parent companies, and all joint venture 

partners: 

(i) A listing of the name and address 

of each company location where any 

employee worked for the period January 

1, 2006 through December 31, 2006. 

(ii) The average number of employees 

at each location based on the number of 

employees for each pay period for the 

period January 1, 2006 through 

December 31, 2006. 

(iii) The type of business activities 

carried out at each location. 

(iv) For joint ventures, the total 

number of employees includes the 

combined employee count of all 

corporate entities in the venture. 

(v) For government-owned refiners, 

the total employee count includes all 

government employees. 

(vi) The total corporate crude oil 

capacity of each refinery as reported to 

the Energy Information Administration 

(EIA) of the U.S. Department of Energy 

(DOE), for the period January 1, 2006 

through December 31, 2006. The 

information submitted to EIA is 

presumed to be correct. In cases where 

a company disagrees with this 

information, the company may petition 

EPA with appropriate data to correct the 

record when the company submits its 

application. 

(vii) A letter signed by the president, 

chief operating or chief executive officer 

of the company, or his/her designee, 

stating that the information contained in 

the application is true to the best of his/ 

her knowledge. 

(viii) Name, address, phone number, 

facsimile number, and e-mail address of 

a corporate contact person. 

(3) In the case of a refiner who 

acquires or reactivates a refinery that 

was shut down or non-operational 

between January 1, 2005 and January 1, 

2006, the information required in 

paragraph (b)(2) of this section must be 

provided for the time period since the 

refiner acquired or reactivated the 

refinery. 

(4) EPA will notify a refiner of its 

approval or disapproval of the 

application for small refiner status by 

letter. 

(5) For foreign refiners the small 

refiner exemption shall be effective 

upon approval, by EPA, of a small 

refiner application. The application 

must contain all of the elements 

required for small refiner status 

applications (as specified in paragraph 

(b)(2) of this section), must satisfy the 

provisions of § 80.1465(f) through (h) 

and (o), must demonstrate compliance 

with the crude oil capacity criterion of 

paragraph (a)(1)(iii) of this section, and 

must be submitted by January 1, 2010 to 

one of the addresses listed in paragraph 

(i) of this section. 

(c) Small refiner temporary 

exemption. (1) Transportation fuel 

produced by a refiner, or foreign refiner 

(as defined at § 80.1465(a)), is exempt 

through December 31, 2010 from the 

renewable fuel standards of § 80.1405 

and the requirements that apply to 

obligated parties under this subpart if 

the refiner or foreign refiner meets all of 

the following criteria: 

(i) The refiner produced 

transportation fuel at its refineries by 

processing crude oil through refinery 

processing units from January 1, 2006 

through December 31, 2006. 

(ii) The refiner employed an average 

of no more than 1,500 people, based on 

the average number of employees for all 

pay periods for calendar year 2006 for 

all subsidiary companies, all parent 

companies, all subsidiaries of the parent 

companies, and all joint venture 

partners. 

(iii) The refiner had a corporateaverage crude oil capacity less than or 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25127 

equal to 155,000 barrels per calendar 

day (bpcd) for 2006. 

(2) The small refiner exemption shall 

apply to an approved small refiner 

unless that refiner chooses to waive this 

exemption (as described in paragraph 

(d) of this section). 

(d)(1) A refiner with approved small 

refiner status may, at any time, waive 

the small refiner exemption under 

paragraph (c) of this section upon 

notification to EPA. 

(2) A refiner’s notice to EPA that it 

intends to waive the small refiner 

exemption must be received by 

November 1 of a given year in order for 

the waiver to be effective for the 

following calendar year. The waiver will 

be effective beginning on January 1 of 

the following calendar year, at which 

point the refiner will be subject to the 

renewable fuel standards of § 80.1405 

and the requirements that apply to 

obligated parties under this subpart. 

(3) The waiver must be sent to EPA 

at one of the addresses listed in 

paragraph (j) of this section. 

(e) Refiners who qualify as small 

refiners under this section and 

subsequently fail to meet all of the 

qualifying criteria as set out in 

paragraph (a) of this section are 

disqualified as small refiners as of the 

effective date of this subpart, except as 

provided under paragraphs (d) and 

(e)(2) of this section. 

(1) In the event such disqualification 

occurs, the refiner shall notify EPA in 

writing no later than 20 days following 

the disqualifying event. 

(2) Disqualification under this 

paragraph (e) shall not apply in the case 

of a merger between two approved small 

refiners. 

(f) If EPA finds that a refiner provided 

false or inaccurate information in its 

application for small refiner status 

under this subpart M, the refiner will be 

disqualified as a small refiner as of the 

effective date of this subpart. 

(g) Any refiner that acquires a refinery 

from another refiner with approved 

small refiner status under paragraph (a) 

of this section shall notify EPA in 

writing no later than 20 days following 

the acquisition. 

(h) Extensions of the small refiner 

temporary exemption. (1) A small 

refiner may apply for an extension of 

the temporary exemption of paragraph 

(c)(1) of this section based on a showing 

of all the following: 

(i) Circumstances exist that impose 

disproportionate economic hardship on 

the refiner and significantly affect the 

refiner’s ability to comply with the RFS 

standards. 

(ii) The refiner has made best efforts 

to comply with the requirements of this 

subpart. 

(2) A refiner must apply, and be 

approved, for small refiner status under 

this section. 

(3) A small refiner’s hardship 

application must include all the 

following information: 

(i) A plan demonstrating how the 

refiner will comply with the 

requirements of § 80.1405 (and all other 

requirements of this subpart applicable 

to obligated parties), as expeditiously as 

possible. 

(ii) A detailed description of the 

refinery configuration and operations 

including, at a minimum, all the 

following information: 

(A) The refinery’s total crude 

capacity. 

(B) Total crude capacity of any other 

refineries owned by the same entity. 

(C) Total volume of gasoline and 

diesel produced at the refinery. 

(D) Detailed descriptions of efforts to 

comply. 

(E) Bond rating of the entity that owns 

the refinery. 

(F) Estimated investment needed to 

comply with the requirements of this 

subpart. 

(4) A small refiner shall notify EPA in 

writing of any changes to its situation 

between approval of the extension 

application and the end of its approved 

extension period. 

(5) EPA may impose reasonable 

conditions on extensions of the 

temporary exemption, including 

reducing the length of such an 

extension, if conditions or situations 

change between approval of the 

application and the end of the approved 

extension period. 

(i) Applications for small refiner 

status, small refiner exemption waivers, 

or extensions of the small refiner 

temporary exemption under this section 

must be sent to one of the following 

addresses: 

(1) For US Mail: U.S. EPA, Attn: RFS2 

Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS2 Program, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. (202) 343–9038. 

§ 80.1443 What are the opt-in provisions 

for noncontiguous states and territories? 

(a) Alaska or a United States territory 

may petition the Administrator to optin to the program requirements of this 

subpart. 

(b) The Administrator will approve 

the petition if it meets the provisions of 

paragraphs (c) and (d) of this section. 

(c) The petition must be signed by the 

Governor of the state or his authorized 

representative (or the equivalent official 

of the territory). 

(d)(1) A petition submitted under this 

section must be received by EPA by 

November 1 for the state or territory to 

be included in the RFS program in the 

next calendar year. 

(2) A petition submitted under this 

section should be sent to either of the 

following addresses: 

(i) For US Mail: U.S. EPA, Attn: RFS 

Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(ii) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. (202) 343–9038. 

(e) Upon approval of the petition by 

the Administrator: 

(1) EPA shall calculate the standards 

for the following year, including the 

total gasoline and diesel fuel volume for 

the state or territory in question. 

(2) Beginning on January 1 of the next 

calendar year, all gasoline and diesel 

fuel refiners and importers in the state 

or territory for which a petition has been 

approved shall be obligated parties as 

defined in § 80.1406. 

(3) Beginning on January 1 of the next 

calendar year, all renewable fuel 

producers in the state or territory for 

which a petition has been approved 

shall, pursuant to § 80.1426(a)(2), be 

required to generate RINs and comply 

with other requirements of this subpart 

M that are applicable to producers of 

renewable fuel. 

§ 80.1444–80.1448 [Reserved] 

§ 80.1449 What are the Production Outlook 

Report requirements? 

(a) A renewable fuel producer or 

importer, for each of its facilities, must 

submit all the following information, as 

applicable, to EPA annually beginning 

February 28, 2010: 

(1) The type, or types, of renewable 

fuel expected to be produced or 

imported at each facility owned by the 

renewable fuel producer or importer. 

(2) The volume of each type of 

renewable fuel expected to be produced 

or imported at each facility. 

(3) The number of RINs expected to be 

generated by the renewable fuel 

producer or importer for each type of 

renewable fuel. 

(4) Information about all the 

following: 

(i) Existing and planned production 

capacity. 

(ii) Long-range plans. 

(iii) Feedstocks and production 

processes to be used at each production 

facility. 

(iv) Changes to the facility that would 

raise or lower emissions of any 

greenhouse gases from the facility. 

25128 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(5) For expanded production capacity 

that is planned or underway at each 

existing facility, or new production 

facilities that are planned or underway, 

information on all the following: 

(i) Strategic planning. 

(ii) Planning and front-end 

engineering. 

(iii) Detailed engineering and 

permitting. 

(iv) Procurement and construction. 

(v) Commissioning and startup. 

(6) Whether capital commitments 

have been made or are projected to be 

made. 

(b) The information listed in 

paragraph (a) of this section shall 

include the reporting party’s best 

estimates for the five following calendar 

years. 

(c) Production outlook reports must 

provide an update of the progress in 

each of the areas listed in paragraph 

(a)(5) of this section. 

(d) Production outlook reports shall 

be sent to one of the following 

addresses: 

(1) For US Mail: U.S. EPA, Attn: RFS2 

Program-Production Outlook Reports, 

6406J, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS2 ProgramProduction Outlook Reports, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. (202) 343–9038. 

§ 80.1450 What are the registration 

requirements under the RFS program? 

(a) Obligated Parties and Exporters. 

Any obligated party described in 

§ 80.1406, and any exporter of 

renewable fuel described in § 80.1430, 

must provide EPA with the information 

specified for registration under § 80.76, 

if such information has not already been 

provided under the provisions of this 

part. An obligated party or an exporter 

of renewable fuel must receive EPAissued identification numbers prior to 

engaging in any transaction involving 

RINs. Registration information must be 

submitted to EPA by January 1, 2010 or 

60 days prior to engaging in any 

transaction involving RINs, whichever 

is later. 

(b) Producers. Except as provided in 

§ 80.1426(b)(1), any foreign or domestic 

producer of renewable fuel, regardless 

of whether RINs will be generated for 

that renewable fuel, must provide EPA 

the information specified under § 80.76 

if such information has not already been 

provided under the provisions of this 

part, and must receive EPA-issued 

company and facility identification 

numbers prior to generating or assigning 

any RINs. All the following registration 

information must be submitted to EPA 

by January 1, 2010 or 60 days prior to 

the production of any renewable fuel 

subject to this subpart, whichever is 

later: 

(1) A description of the types of 

renewable fuels and co-products 

produced at the facility and all the 

following for each product type: 

(i) A list of the feedstocks capable of 

being utilized by the facility. 

(ii) A description of the facility’s 

renewable fuel production processes. 

(iii) The facility’s renewable fuel 

production capacity. 

(iv) A list of the facility’s process 

energy sources. 

(v) For a producer of renewable fuel 

with a facility that commenced 

construction on or before December 19, 

2007 per § 80.1403: 

(A) The location of the facility. 

(B) Record of costs of additions, 

replacements, and repairs inclusive of 

labor costs conducted at the facility 

since December 19, 2007. 

(C) The estimated life of the facility. 

(D) A discussion of any economic or 

technical limitations the facility may 

have in using a fuel production pathway 

that will achieve a 20 percent reduction 

in GHG as compared to baseline fuel. 

(2) An independent third party 

engineering review and written 

verification of the descriptions made 

pursuant to paragraph (b)(1) of this 

section. 

(i) The verifications required under 

this section must be conducted by a 

licensed Professional Engineer who 

works in the chemical engineering field 

and who is licensed by the appropriate 

state agency. 

(ii) To be considered an independent 

third party under this paragraph (b)(2): 

(A) The third party shall not be 

operated by the renewable fuel producer 

or any subsidiary or employee of the 

renewable fuel producer. 

(B) The third party shall be free from 

any interest in the renewable fuel 

producer’s business. 

(C) The renewable fuel producer shall 

be free from any interest in the third 

party’s business. 

(D) Use of a third party that is 

debarred, suspended, or proposed for 

debarment pursuant to the Governmentwide Debarment and Suspension 

regulations, 40 CFR part 32, or the 

Debarment, Suspension and Ineligibility 

provisions of the Federal Acquisition 

Regulations, 48 CFR, part 9, subpart 9.4, 

shall be deemed noncompliance with 

the requirements of this section. 

(iii) The independent third party shall 

retain all records pertaining to the 

verification required under this section 

for a period of five years from the date 

of creation and shall deliver such 

records to the Administrator upon 

request. 

(iv) The renewable fuel producer must 

retain records of the review and 

verification, as required in 

§ 80.1451(b)(7). 

(c) Importers. Importers of renewable 

fuel must provide EPA the information 

specified under § 80.76, if such 

information has not already been 

provided under the provisions of this 

part and must receive an EPA-issued 

company identification number prior to 

owning any RINs. Registration 

information may be submitted to EPA 

by January 1, 2010 or 60 days prior to 

engaging in any transaction involving 

RINs, whichever is later. 

(d) Registration updates. Except as 

provided in § 80.1426(b)(1): 

(1) Any producer of renewable fuel 

who makes changes to his facility that 

will qualify his renewable fuel for a 

renewable fuel category or D code as 

defined in § 80.1425(g) that is not 

reflected in the producer’s registration 

information on file with EPA must 

update his registration information and 

submit a copy of an updated 

independent engineering review at least 

60 days prior to producing the new type 

of renewable fuel. 

(2) Any producer of renewable fuel 

who makes any other changes to a 

facility not affecting the renewable fuel 

category for which the producer is 

registered must update his registration 

information within 7 days of the change. 

(e) Parties who own RINs or who 

intend to own RINs. Any party who 

owns or intends to own RINs, but who 

is not covered by paragraphs (a), (b), or 

(d) of this section, must provide EPA the 

information specified under § 80.76, if 

such information has not already been 

provided under the provisions of this 

part and must receive an EPA-issued 

company identification number prior to 

owning any RINs. Registration 

information must be submitted to EPA 

by January 1, 2010 or 60 days prior to 

engaging in any transaction involving 

RINs, whichever is later. 

(f) Registration shall be on forms, and 

following policies, established by the 

Administrator. 

§ 80.1451 What are the recordkeeping 

requirements under the RFS program? 

(a) Beginning January 1, 2010, any 

obligated party (as described at 

§ 80.1406) or exporter of renewable fuel 

(as described at § 80.1430) must keep all 

of the following records: 

(1) Product transfer documents 

consistent with § 80.1453 and associated 

with the obligated party’s activity, if 

any, as transferor or transferee of 

renewable fuel. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25129 

(2) Copies of all reports submitted to 

EPA under §§ 80.1449 and 80.1452(a). 

(3) Records related to each RIN 

transaction, including all the following: 

(i) A list of the RINs owned, 

purchased, sold, retired, or reinstated. 

(ii) The parties involved in each RIN 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(4) Records related to the use of RINs 

(by facility, if applicable) for 

compliance, including all the following: 

(i) Methods and variables used to 

calculate the Renewable Volume 

Obligations pursuant to § 80.1407 or 

§ 80.1430. 

(ii) List of RINs used to demonstrate 

compliance. 

(iii) Additional information related to 

details of RIN use for compliance. 

(b) Beginning January 1, 2010, any 

foreign or domestic producer of a 

renewable fuel as defined in § 80.1401 

must keep all of the following records: 

(1) Product transfer documents 

consistent with § 80.1453 and associated 

with the renewable fuel producer’s 

activity, if any, as transferor or 

transferee of renewable fuel. 

(2) Copies of all reports submitted to 

EPA under §§ 80.1449 and 80.1452(b). 

(3) Records related to the generation 

and assignment of RINs for each facility, 

including all of the following: 

(i) Batch volume in gallons. 

(ii) Batch number. 

(iii) RIN as assigned under § 80.1426. 

(iv) Identification of batches by 

renewable category. 

(v) Date of production. 

(vi) Results of any laboratory analysis 

of batch chemical composition or 

physical properties. 

(vii) Additional information related to 

details of RIN generation. 

(4) Records related to each RIN 

transaction, including all of the 

following: 

(i) A list of the RINs owned, 

purchased, sold, retired, or reinstated. 

(ii) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(5) Records related to the production, 

importation, ownership, sale or use of 

any volume of renewable fuel or blend 

of renewable fuel and gasoline or diesel 

fuel that any party designates for use as 

transportation fuel, jet fuel, or home 

heating oil and the use of the fuel or 

blend as transportation fuel, jet fuel, or 

home heating oil without further 

blending, in the designated form. 

(6) Documents associated with 

feedstock purchases and transfers that 

identify where the feedstocks were 

produced and are sufficient to verify 

that feedstocks used are renewable 

biomass (as defined in § 80.1401) if RINs 

are generated, or sufficient to verify that 

feedstocks used are not renewable 

biomass if no RINs are generated. 

(i) Renewable fuel producers who use 

planted crops or crop residue from 

existing agricultural land, or who use 

planted trees or slash from actively 

managed tree plantations must keep 

records that serve as evidence that the 

land from which the feedstock was 

obtained was continuously actively 

managed or fallow, and nonforested, 

since December 19, 2007. The records 

must be provided by the feedstock 

producer and consist of at least one of 

the following documents: Sales records 

for planted crops or trees, crop residue, 

livestock, or slash; purchasing records 

for fertilizer, weed control, or reseeding, 

including seeds, seedlings, or other 

nursery stock; a written management 

plan for agricultural or silvicultural 

purposes; documentation of 

participation in an agricultural, or 

silvicultural program sponsored by a 

Federal, state or local government 

agency; or documentation of land 

management in accordance with an 

agricultural or silvicultural product 

certification program. 

(ii) Renewable fuel producers who use 

any other type of renewable biomass 

must have written certification from 

their feedstock supplier that the 

feedstock qualifies as renewable 

biomass. 

(iii) Renewable fuel producers who do 

not use renewable biomass must have 

written certification from their feedstock 

supplier that the feedstock does not 

qualify as renewable biomass. 

(7) Copies of registration documents 

required under § 80.1450, including 

information on fuels and products, 

feedstocks, facility production processes 

and capacity, energy sources, and 

independent third party engineering 

review. 

(c) Beginning January 1, 2010, any 

importer of a renewable fuel (as defined 

in § 80.1401) must keep all of the 

following records: 

(1) Product transfer documents 

consistent with § 80.1453 and associated 

with the renewable fuel importer’s 

activity, if any, as transferor or 

transferee of renewable fuel. 

(2) Copies of all reports submitted to 

EPA under §§ 80.1449 and 80.1452(b); 

however, duplicate records are not 

required. 

(3) Records related to the generation 

and assignment of RINs for each facility, 

including all of the following: 

(i) Batch volume in gallons. 

(ii) Batch number. 

(iii) RIN as assigned under § 80.1426. 

(iv) Identification of batches by 

renewable category. 

(v) Date of import. 

(vi) Results of any laboratory analysis 

of batch chemical composition or 

physical properties. 

(vii) Additional information related to 

details of RIN generation. 

(4) Records related to each RIN 

transaction, including all of the 

following: 

(i) A list of the RINs owned, 

purchased, sold, retired, or reinstated. 

(ii) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(5) Documents associated with 

feedstock purchases and transfers, 

sufficient to verify that feedstocks used 

are renewable biomass (as defined in 

§ 80.1401) if the importer generates 

RINs. 

(6) Documents associated with 

feedstock purchases and transfers, 

sufficient to verify that feedstocks used 

are not renewable biomass as defined in 

§ 80.1401 if the importer does not 

generate RINs. 

(7) Copies of registration documents 

required under § 80.1450. 

(8) Records related to the import of 

any volume of renewable fuel that the 

importer designates for use as 

transportation fuel, jet fuel, or home 

heating oil. 

(d) Beginning January 1, 2010, any 

production facility with a baseline 

volume of fuel that is not subject to the 

20% GHG threshold, pursuant to 

§ 80.1403(a), must keep all of the 

following: 

(1) Detailed engineering plans for the 

facility. 

(2) Federal, State, and local 

preconstruction approvals and 

permitting. 

(3) Procurement and construction 

contracts and agreements. 

(4) Records of electricity consumption 

and energy use. 

(5) Records showing costs of 

additions, replacements, and repairs 

inclusive of labor costs conducted at the 

facility since December 19, 2007. 

(6) Records estimating the life of the 

existing facility. 

(e) Beginning January 1, 2010, any 

party, other than those parties covered 

in paragraphs (a) and (b) of this section, 

25130 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

that owns RINs must keep all of the 

following records: 

(1) Product transfer documents 

consistent with § 80.1453 and associated 

with the party’s activity, if any, as 

transferor or transferee of renewable 

fuel. 

(2) Copies of all reports submitted to 

EPA under § 80.1452(c). 

(3) Records related to each RIN 

transaction by renewable fuel category, 

including all of the following: 

(i) A list of the RINs owned, 

purchased, sold, retired, or reinstated. 

(ii) The parties involved in each RIN 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The date of the transfer of the 

RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(4) Records related to any volume of 

renewable fuel that the party designated 

for use as transportation fuel, jet fuel, or 

home heating oil and from which RINs 

were separated pursuant to 

§ 80.1429(b)(4). 

(f) The records required under 

paragraphs (a) through (c) of this section 

and under § 80.1453 shall be kept for 

five years from the date they were 

created, except that records related to 

transactions involving RINs shall be 

kept for five years from the date of 

transfer. 

(g) The records required under 

paragraph (d) of this section shall be 

kept through calendar year 2022. 

(h) On request by EPA, the records 

required under this section and under 

§ 80.1453 must be made available to the 

Administrator or the Administrator’s 

authorized representative. For records 

that are electronically generated or 

maintained, the equipment or software 

necessary to read the records shall be 

made available; or, if requested by EPA, 

electronic records shall be converted to 

paper documents. 

(i) The records required in paragraphs 

(b)(6) and (b)(7) of this section must be 

provided to the importer of the 

renewable fuel by any foreign producer 

not generating RINs for his renewable 

fuel. 

§ 80.1452 What are the reporting 

requirements under the RFS program? 

(a) Obligated parties and exporters. 

Any obligated party described in 

§ 80.1406 or exporter of renewable fuel 

described in § 80.1430 must submit to 

EPA reports according to the schedule, 

and containing all the information, that 

is set forth in this paragraph (a). 

(1) Annual compliance demonstration 

reports for the previous compliance 

period shall be submitted on February 

28 of each year and shall include all of 

the following information: 

(i) The obligated party’s name. 

(ii) The EPA company registration 

number. 

(iii) Whether the party is complying 

on a corporate (aggregate) or facility-byfacility basis. 

(iv) The EPA facility registration 

number, if complying on a facility-byfacility basis. 

(v) The production volume of all of 

the products listed in § 80.1407(c) and 

(f) for the reporting year. 

(vi) The RVOs, as defined in 

§ 80.1427(a) for obligated parties and 

§ 80.1430(b) for exporters of renewable 

fuel, for the reporting year. 

(vii) Any deficit RVOs carried over 

from the previous year. 

(viii) The total current-year RINs by 

type of renewable fuel, as those fuels are 

defined in § 80.1401 (i.e., cellulosic 

biofuel, biomass-based diesel, advanced 

biofuels, and renewable fuels), used for 

compliance. 

(ix) The total prior-year RINs by 

renewable fuel type, as those fuels are 

defined in § 80.1401, used for 

compliance. 

(x) A list of all RINs used for 

compliance in the reporting year. 

(A) For the 2010 reporting year only 

(January 1—December 31, 2010), a list of 

all 38-digit RINs used to demonstrate 

compliance. 

(B) Starting January 1, 2011, RINs 

used to meet compliance will be 

conveyed via the EPA Moderated 

Transaction System (EMTS) as set forth 

in paragraph (e) of this section. 

(xi) Any deficit RVO(s) carried into 

the subsequent year. 

(xii) Any additional information that 

the Administrator may require. 

(2) The RIN transaction reports 

required under paragraph (c)(1) of this 

section. 

(3) The quarterly RIN activity reports 

required under paragraph (c)(2) of this 

section. 

(4) Reports required under this 

paragraph (a) must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the 

owner or a responsible corporate officer 

of the obligated party. 

(b) Renewable fuel producers 

(domestic and foreign) and importers. 

Any domestic producer or importer of 

renewable fuel, or foreign renewable 

fuel producer who generates RINs, must 

submit to EPA reports according to the 

schedule, and containing all the 

information, that is set forth in this 

paragraph (b). 

(1)(i) Until December 31, 2010, 

renewable fuel production reports for 

each facility owned by the renewable 

fuel producer or importer shall be 

submitted monthly, according to the 

schedule specified in paragraph (d)(1) of 

this section. 

(ii) Starting January 1, 2011, 

renewable fuel production reports for 

each facility owned by the renewable 

fuel producer or importer shall be 

submitted in accordance with paragraph 

(e)(2) of this section. 

(iii) The renewable fuel production 

reports shall include all the following 

information for each batch of renewable 

fuel produced, where ‘‘batch’’ means a 

discrete quantity of renewable fuel 

produced and either assigned or not 

assigned a unique batch-RIN per 

§ 80.1426(b)(2): 

(A) The renewable fuel producer’s 

name. 

(B) The EPA company registration 

number. 

(C) The EPA facility registration 

number. 

(D) The applicable monthly reporting 

period. 

(E) Whether RINs were generated for 

each batch according to § 80.1426. 

(F) The production date of each batch. 

(G) The type of renewable fuel of each 

batch, as defined in § 80.1401. 

(H) Information related to the volume 

of denaturant and applicable 

equivalence value of each batch. 

(I) The volume of each batch 

produced. 

(J) The process(es) and feedstock(s) 

used and proportion of renewable 

volume attributable to each process and 

feedstock. 

(K) The type and volume of coproducts produced with each batch of 

renewable fuel. 

(L) In the case that RINs were 

generated for the batch, a list of the RINs 

generated and a certification that the 

feedstock(s) used for each batch meets 

the definition of renewable biomass as 

defined in § 80.1401. 

(M) In the case that RINs were not 

generated for the batch, an explanation 

as to the reason for not generating RINs. 

(N) Any additional information the 

Administrator may require. 

(2) The RIN transaction reports 

required under paragraph (c)(1) of this 

section. 

(3) The quarterly RIN activity reports 

required under paragraph (c)(2) of this 

section. 

(4) Reports required under this 

paragraph (b) must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the 

owner or a responsible corporate officer 

of the renewable fuel producer. 

(c) All RIN-owning parties. Any party, 

including any party specified in 

paragraphs (a) and (b) of this section, 

that owns RINs during a reporting 

period, must submit reports to EPA 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25131 

according to the schedule, and 

containing all the information, that is 

set forth in this paragraph (c). 

(1)(i) Until December 31, 2010, RIN 

transaction reports listing each RIN 

transaction shall be submitted monthly 

according to the schedule in paragraph 

(d)(1) of this section. 

(ii) Starting January 1, 2011, RIN 

transaction reports listing each RIN 

transaction shall be submitted in 

accordance with paragraph (e)(3) of this 

section. 

(iii) Each report required by paragraph 

(c)(1)(i) of this section shall include all 

of the following information: 

(A) The submitting party’s name. 

(B) The party’s EPA company 

registration number. 

(C) [Reserved] 

(D) The applicable monthly reporting 

period. 

(E) Transaction type (i.e., RIN 

purchase, RIN sale, retired RIN, 

reinstated 2009 RIN). 

(F) Transaction date. 

(G) For a RIN purchase or sale, the 

trading partner’s name. 

(H) For a RIN purchase or sale, the 

trading partner’s EPA company 

registration number. For all other 

transactions, the submitting party’s EPA 

company registration number. 

(I) RIN subject to the transaction. 

(J) For a RIN purchase or sale, the per 

gallon RIN price and/or the per gallon 

renewable price if the RIN price is 

included. 

(K) For a retired RIN, the reason for 

retiring the RIN (e.g., invalid RIN under 

§ 80.1431, reportable spill under 

§ 80.1432, foreign producer volume 

correction under § 80.1466(e), 

renewable fuel used in a boiler or oceangoing vessel under § 80.1429(f), 

enforcement obligation, or use for 

compliance (per paragraph (a)(1)(x) of 

this section), etc.). 

(L) Any additional information that 

the Administrator may require. 

(2) Quarterly RIN activity reports shall 

be submitted to EPA according to the 

schedule specified in paragraph (d)(2) of 

this section. Each report shall 

summarize RIN activities for the 

reporting period, separately for RINs 

separated from a renewable fuel volume 

and the sum of both RINs assigned to a 

renewable fuel volume and RINs 

generated, but not assigned to a 

renewable fuel volume. The quarterly 

RIN activity reports shall include all of 

the following information: 

(i) The submitting party’s name. 

(ii) The party’s EPA company 

registration number. 

(iii) The number of current-year RINs 

owned at the start of the month. 

(iv) The number of prior-year RINs 

owned at the start of the month. 

(v) The total current-year RINs 

purchased. 

(vi) The total prior-year RINs 

purchased. 

(vii) The total current-year RINs sold. 

(viii) The total prior-year RINs sold. 

(ix) The total current-year RINs 

retired. 

(x) The total prior-year RINs retired. 

(xi) The number of current-year RINs 

owned at the end of the quarter. 

(xii) The number of prior-year RINs 

owned at the end of the quarter. 

(xiii) For parties reporting RIN 

activity under this paragraph for RINs 

generated, but not assigned to a 

renewable fuel volume and/or RINs 

assigned to a volume of renewable fuel, 

and the volume of renewable fuel (in 

gallons) owned at the end of the quarter. 

(xiv) The total 2009 retired RINs 

reinstated. 

(xv) Any additional information that 

the Administrator may require. 

(3) All reports required under this 

paragraph (c) must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the RIN 

owner or a responsible corporate officer 

of the RIN owner. 

(d) Report submission deadlines. The 

submission deadlines for monthly and 

quarterly reports shall be as follows: 

(1) Monthly reports shall be submitted 

to EPA by the last day of the next 

calendar month following the 

compliance period (i.e., the report 

covering January would be due by 

February 28th, the report covering 

February would be due by March 31st, 

etc.). 

(2) Quarterly reports shall be 

submitted to EPA by the last day of the 

second month following the compliance 

period (i.e., the report covering January– 

March would be due by May 31st, the 

report covering April–June would be 

due by August 31st, the report covering 

July–September would be due by 

November 30th and the report covering 

October–December would be due by 

February 28th). 

(e) EPA Moderated Transaction 

System (EMTS). (1) Each party required 

to report under this section must 

establish an account with EMTS by 

October 1, 2010 or sixty (60) days prior 

to engaging in any transaction involving 

RINs, whichever is later. 

(2) Starting January 1, 2011, each time 

a domestic producer or importer of 

renewable fuel, or foreign renewable 

fuel producer who generates RINs, 

produces or imports a batch of 

renewable fuel, all the following 

information must be submitted to EPA 

within three (3) business days: 

(i) The renewable fuel producer’s or 

importer’s name. 

(ii) The EPA company registration 

number. 

(iii) The EPA facility registration 

number. 

(iv) Whether RINs were generated for 

the batch, according to § 80.1426. 

(v) The production date of the batch. 

(vi) The type of renewable fuel of the 

batch, as defined in § 80.1401. 

(vii) Information related to the volume 

of denaturant and applicable 

equivalence value of each batch. 

(viii) The volume of the batch. 

(ix) The process(es) and feedstock(s) 

used and proportion of renewable 

volume attributable to each process and 

feedstock. 

(x) A certification that the feedstock(s) 

used for each batch meets the definition 

of renewable biomass as defined in 

§ 80.1401. 

(xi) The type and volume of coproducts produced with the batch of 

renewable fuel. 

(xii) In the case that RINs were 

generated for the batch, a list of the RINs 

generated and a certification that the 

feedstock(s) used for each batch meets 

the definition of renewable biomass as 

defined in § 80.1401. 

(xiii) In the case that RINs were not 

generated for the batch, an explanation 

as to the reason for not generating RINs. 

(xiv) Any additional information the 

Administrator may require. 

(3) Starting January 1, 2011, each time 

any party engages in a transaction 

involving RINs, all the following 

information must be submitted to EPA 

within three (3) business days: 

(i) The submitting party’s name. 

(ii) The party’s EPA company 

registration number. 

(iii) [Reserved] 

(iv) The applicable monthly reporting 

period. 

(v) Transaction type (i.e., RIN 

purchase, RIN sale, retired RIN). 

(vi) Transaction date. 

(vii) For a RIN purchase or sale, the 

trading partner’s name. 

(viii) For a RIN purchase or sale, the 

trading partner’s EPA company 

registration number. For all other 

transactions, the submitting party’s EPA 

company registration number. 

(ix) RIN subject to the transaction. 

(x) For a RIN purchase or sale, the per 

gallon RIN price and/or the per gallon 

renewable price if the RIN price is 

included. 

(xi) For a retired RIN, the reason for 

retiring the RIN (e.g., reportable spill 

under § 80.1432, foreign producer 

volume correction under § 80.1466(e), 

renewable fuel used in a boiler or oceangoing vessel under § 80.1429(f), 

enforcement obligation, or use for 

compliance (per paragraph (a)(1)(x) of 

this section), etc.). 

25132 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(xii) Any additional information that 

the Administrator may require. 

(f) All reports required under this 

section shall be submitted on forms and 

following procedures prescribed by the 

Administrator. 

§ 80.1453 What are the product transfer 

document (PTD) requirements for the RFS 

program? 

(a) On each occasion when any party 

transfers ownership of renewable fuels 

subject to this subpart, the transferor 

must provide to the transferee 

documents identifying the renewable 

fuel and any assigned RINs which 

include all of the following information, 

as applicable: 

(1) The name and address of the 

transferor and transferee. 

(2) The transferor’s and transferee’s 

EPA company registration number. 

(3) The volume of renewable fuel that 

is being transferred. 

(4) The date of the transfer. 

(5) Whether any RINs are assigned to 

the volume, as follows: 

(i) If the assigned RINs are being 

transferred on the same PTD used to 

transfer ownership of the renewable 

fuel, then the assigned RINs shall be 

listed on the PTD. 

(ii) If the assigned RINs are being 

transferred on a separate PTD from that 

which is used to transfer ownership of 

the renewable fuel, then the PTD which 

is used to transfer ownership of the 

renewable fuel shall state the number of 

gallon-RINs being transferred as well as 

a unique reference to the PTD which is 

transferring the assigned RINs. 

(iii) If no assigned RINs are being 

transferred with the renewable fuel, the 

PTD which is used to transfer 

ownership of the renewable fuel shall 

state ‘‘No assigned RINs transferred’’. 

(iv) If RINs have been separated from 

the renewable fuel or blend pursuant to 

§ 80.1129(b)(4), then all PTDs which are 

at any time used to transfer ownership 

of the renewable fuel or blend shall 

state, ‘‘This volume of fuel must be used 

in the designated form, without further 

blending.’’. 

(b) Except for transfers to truck 

carriers, retailers, or wholesale 

purchaser-consumers, product codes 

may be used to convey the information 

required under paragraphs (a)(1) 

through (a)(4) of this section if such 

codes are clearly understood by each 

transferee. 

(c) The RIN number required under 

paragraph (a)(5) of this section must 

always appear in its entirety. 

(d) If a RIN is traded in the EPA– 

Moderated Trading System (EMTS) as 

described in § 80.1452(e), the transferor 

must provide to the transferee 

documents that include all information 

as described in paragraphs (a) and (b) of 

this section and the number of RINs 

transferred identified by all the 

following: 

(1) Assignment (Assigned or 

Separated). 

(2) Type and/or D code (cellulosic 

biofuel D=1, biomass-based diesel D=2, 

advanced biofuel D=3, renewable fuel 

D=4). 

(3) RIN generation year. 

§ 80.1454 What are the provisions for 

renewable fuel production facilities and 

importers who produce or import less than 

10,000 gallons of renewable fuel per year? 

(a) Renewable fuel production 

facilities located within the United 

States that produce less than 10,000 

gallons of renewable fuel each year, and 

importers who import less than 10,000 

gallons of renewable fuel each year, are 

not required to generate RINs or to 

assign RINs to batches of renewable 

fuel. Except as stated in paragraph (b) of 

this section, such production facilities 

and importers that do not generate and/ 

or assign RINs to batches of renewable 

fuel are also exempt from all the 

following requirements of this subpart: 

(1) The recordkeeping requirements of 

§ 80.1451. 

(2) The reporting requirements of 

§ 80.1452. 

(3) The attest engagement 

requirements of § 80.1464. 

(4) The production outlook report 

requirements of § 80.1449. 

(b)(1) Renewable fuel production 

facilities and importers who produce or 

import less than 10,000 gallons of 

renewable fuel each year and that 

generate and/or assign RINs to batches 

of renewable fuel are subject to the 

provisions of §§ 80.1449 through 

80.1452, and 80.1464. 

(2) Renewable fuel production 

facilities and importers who produce or 

import less than 10,000 gallons of 

renewable fuel each year but wish to 

own RINs will be subject to all 

requirements stated in paragraphs (a)(1) 

through (a)(4) of this section, and all 

other applicable requirements of this 

subpart M. 

§ 80.1455 What are the provisions for 

cellulosic biofuel allowances? 

(a) If EPA reduces the applicable 

volume of cellulosic biofuel pursuant to 

section 211(o)(7)(D)(i) of the Clean Air 

Act (42 U.S.C. 7545(o)(7)(D)(i)) for any 

given compliance year, then EPA will 

provide cellulosic biofuel allowances 

for purchase for that compliance year. 

(1) The price of these allowances will 

be set by EPA on an annual basis in 

accordance with paragraph (d) of this 

section. 

(2) The total allowances available will 

be equal to the reduced cellulosic 

biofuel volume established by EPA for 

the compliance year. 

(b) Use of allowances. (1) Allowances 

are only valid for use in the compliance 

year that they are made available. 

(2) Allowances are nonrefundable. 

(3) Allowances are nontransferable 

except if forfeiting the allowances to 

EPA. 

(c) Purchase of allowances. (1) Only 

parties with an RVO for cellulosic 

biofuel may purchase cellulosic biofuel 

allowances. 

(2) Allowances shall be purchased 

from EPA at the time that a party 

submits its annual compliance report to 

EPA pursuant to § 80.1452(a)(1). 

(3) Parties may not purchase more 

allowances than their cellulosic biofuel 

RVO minus cellulosic biofuel RINs with 

a D code of 1 that they own. 

(4) Allowances may be used to meet 

an obligated party’s RVOs for the 

advanced biofuel and total renewable 

fuel standards. 

(d) Setting the price of allowances. (1) 

The price for allowances shall be set 

equal to the greater of: 

(i) $0.25 per allowance, adjusted for 

inflation in comparison to calendar year 

2008; or 

(ii) $3.00 less the wholesale price of 

gasoline per allowance, adjusted for 

inflation in comparison to calendar year 

2008. 

(2) The wholesale price of gasoline 

will be calculated by averaging the most 

recent twelve monthly values for U.S. 

Total Gasoline Bulk Sales (Price) by All 

Sellers as provided by the Energy 

Information Administration that are 

available as of September 30 of the year 

preceding the compliance period. 

(3) The inflation adjustment will be 

calculated by comparing the most recent 

Consumer Price Index for All Urban 

Consumers (CPI–U) for All Items 

expenditure category as provided by the 

Bureau of Labor Statistics that is 

available as of September 30 of the year 

preceding the compliance period to the 

most recent comparable value reported 

prior to December 31, 2008. When EPA 

must set the price of allowances for a 

compliance year, EPA will calculate the 

new amounts for paragraphs (d)(1)(i) 

and (ii) of this section for each year after 

2008 and every month where data is 

available for the year preceding the 

compliance period. 

(e) Cellulosic biofuel allowances 

under this section will only be able to 

be purchased on forms and following 

procedures prescribed by EPA. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25133 

§§ 80.1456–80.1459 [Reserved] 

§ 80.1460 What acts are prohibited under 

the RFS program? 

(a) Renewable fuels producer or 

importer violation. Except as provided 

in § 80.1454, no party shall produce or 

import a renewable fuel without 

assigning the proper number of gallonRINs or identifying it by a batch-RIN as 

required under § 80.1426. 

(b) RIN generation and transfer 

violations. No party shall do any of the 

following: 

(1) Generate a RIN for a fuel that is not 

a renewable fuel, or for which the 

applicable renewable fuel volume was 

not produced. 

(2) Create or transfer to any party a 

RIN that is invalid under § 80.1431. 

(3) Transfer to any party a RIN that is 

not properly identified as required 

under § 80.1425. 

(4) Transfer to any party a RIN with 

a K code of 1 without transferring an 

appropriate volume of renewable fuel to 

the same party on the same day. 

(5) Introduce into commerce any 

renewable fuel produced from a 

feedstock or through a process that is 

not described in the party’s registration 

information. 

(c) RIN use violations. No party shall 

do any of the following: 

(1) Fail to acquire sufficient RINs, or 

use invalid RINs, to meet the party’s 

RVOs under § 80.1427. 

(2) Fail to acquire sufficient RINs to 

meet the party’s RVOs under § 80.1430. 

(3) Use a validly generated RIN to 

meet the party’s RVOs under § 80.1427, 

or separate and transfer a validly 

generated RIN, where the party 

ultimately uses the renewable fuel 

volume associated with the RIN in an 

application other than for use as 

transportation fuel (as defined in 

§ 80.1401). 

(d) RIN retention violation. No party 

shall retain RINs in violation of the 

requirements in § 80.1428(a)(5). 

(e) Causing a violation. No party shall 

cause another party to commit an act in 

violation of any prohibited act under 

this section. 

(f) Failure to meet a requirement. No 

party shall fail to meet any requirement 

that applies to that party under this 

subpart. 

§ 80.1461 Who is liable for violations 

under the RFS program? 

(a) Parties liable for violations of 

prohibited acts. (1) Any party who 

violates a prohibition under § 80.1460(a) 

through (d) is liable for the violation of 

that prohibition. 

(2) Any party who causes another 

person to violate a prohibition under 

§ 80.1460(a) through (d) is liable for a 

violation of § 80.1460(e). 

(b) Parties liable for failure to meet 

other provisions of this subpart. (1) Any 

party who fails to meet a requirement of 

any provision of this subpart is liable for 

a violation of that provision. 

(2) Any party who causes another 

party to fail to meet a requirement of 

any provision of this subpart is liable for 

causing a violation of that provision. 

(c) Parent corporation liability. Any 

parent corporation is liable for any 

violation of this subpart that is 

committed by any of its subsidiaries. 

(d) Joint venture liability. Each partner 

to a joint venture is jointly and severally 

liable for any violation of this subpart 

that is committed by the joint venture 

operation. 

§ 80.1462 [Reserved] 

§ 80.1463 What penalties apply under the 

RFS program? 

(a) Any party who is liable for a 

violation under § 80.1461 is subject a to 

civil penalty of up to $32,500, as 

specified in sections 205 and 211(d) of 

the Clean Air Act, for every day of each 

such violation and the amount of 

economic benefit or savings resulting 

from each violation. 

(b) Any party liable under 

§ 80.1461(a) for a violation of 

§ 80.1460(c) for failure to meet its RVOs, 

or § 80.1460(e) for causing another party 

to fail to meet their RVOs, during any 

averaging period, is subject to a separate 

day of violation for each day in the 

averaging period. 

(c) Any party liable under 

§ 80.1461(b) for failure to meet, or 

causing a failure to meet, a requirement 

of any provision of this subpart is liable 

for a separate day of violation for each 

day such a requirement remains 

unfulfilled. 

§ 80.1464 What are the attest engagement 

requirements under the RFS program? 

The requirements regarding annual 

attest engagements in §§ 80.125 through 

80.127, and 80.130, also apply to any 

attest engagement procedures required 

under this subpart M. In addition to any 

other applicable attest engagement 

procedures, such as the requirements in 

§ 80.1465, the following annual attest 

engagement procedures are required 

under this subpart. 

(a) Obligated parties and exporters. 

The following attest procedures shall be 

completed for any obligated party as 

stated in § 80.1406(a) or exporter of 

renewable fuel that is subject to the 

renewable fuel standard under 

§ 80.1405: 

(1) Annual compliance demonstration 

report. (i) Obtain and read a copy of the 

annual compliance demonstration 

report required under § 80.1452(a)(1) 

which contains information regarding 

all the following: 

(A) The obligated party’s volume of 

finished gasoline, reformulated gasoline 

blendstock for oxygenate blending 

(RBOB), and conventional gasoline 

blendstock that becomes finished 

conventional gasoline upon the addition 

of oxygenate (CBOB) produced or 

imported during the reporting year. 

(B) RVOs. 

(C) RINs used for compliance. 

(ii) Obtain documentation of any 

volumes of renewable fuel used in 

gasoline at the refinery or import facility 

or exported during the reporting year; 

compute and report as a finding the 

total volumes of renewable fuel 

represented in these documents. 

(iii) Compare the volumes of gasoline 

reported to EPA in the report required 

under § 80.1452(a)(1) with the volumes, 

excluding any renewable fuel volumes, 

contained in the inventory 

reconciliation analysis under § 80.133, 

and verify that the volumes reported to 

EPA agree with the volumes in the 

inventory reconciliation analysis. 

(iv) Compute and report as a finding 

the obligated party’s or exporter’s RVOs, 

and any deficit RVOs carried over from 

the previous year or carried into the 

subsequent year, and verify that the 

values agree with the values reported to 

EPA. 

(v) Obtain the database, spreadsheet, 

or other documentation for all RINs 

used for compliance during the year 

being reviewed; calculate the total 

number of RINs used for compliance by 

year of generation represented in these 

documents; state whether this 

information agrees with the report to 

EPA and report as a finding any 

exceptions. 

(2) RIN transaction reports. (i) Obtain 

and read copies of a representative 

sample, selected in accordance with the 

guidelines in § 80.127, of each RIN 

transaction type (RINs purchased, RINs 

sold, RINs retired, RINs reinstated) 

included in the RIN transaction reports 

required under § 80.1452(a)(2) for the 

compliance year. 

(ii) Obtain contracts, invoices, or 

other documentation for the 

representative samples of RIN 

transactions; compute the transaction 

types, transaction dates, and RINs 

traded; state whether the information 

agrees with the party’s reports to EPA 

and report as a finding any exceptions. 

(3) RIN activity reports. (i) Obtain and 

read copies of all quarterly RIN activity 

reports required under § 80.1452(a)(3) 

for the compliance year. 

25134 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(ii) Obtain the database, spreadsheet, 

or other documentation used to generate 

the information in the RIN activity 

reports; compare the RIN transaction 

samples reviewed under paragraph 

(a)(2) of this section with the 

corresponding entries in the database or 

spreadsheet and report as a finding any 

discrepancies; compute the total 

number of current-year and prior-year 

RINs owned at the start and end of the 

quarter, purchased, sold, retired, and 

reinstated, and for parties that reported 

RIN activity for RINs assigned to a 

volume of renewable fuel, the volume of 

renewable fuel owned at the end of the 

quarter; as represented in these 

documents; and state whether this 

information agrees with the party’s 

reports to EPA. 

(b) Renewable fuel producers and 

RIN-generating importers. The following 

attest procedures shall be completed for 

any renewable fuel producer or RINgenerating importer: 

(1) Renewable fuel production reports. 

(i) Obtain and read copies of the 

renewable fuel production reports 

required under §§ 80.1452(b)(1) and 

(e)(2) for the compliance year. 

(ii) Obtain production data for each 

renewable fuel batch produced or 

imported during the year being 

reviewed; compute the RIN numbers, 

production dates, types, volumes of 

denaturant and applicable equivalence 

values, and production volumes for 

each batch; state whether this 

information agrees with the party’s 

reports to EPA and report as a finding 

any exceptions. 

(iii) Verify that the proper number of 

RINs were generated and assigned for 

each batch of renewable fuel produced 

or imported, as required under 

§ 80.1426. 

(iv) Obtain product transfer 

documents for a representative sample, 

selected in accordance with the 

guidelines in § 80.127, of renewable fuel 

batches produced or imported during 

the year being reviewed; verify that the 

product transfer documents contain the 

applicable information required under 

§ 80.1453; verify the accuracy of the 

information contained in the product 

transfer documents; report as a finding 

any product transfer document that does 

not contain the applicable information 

required under § 80.1453. 

(v) Obtain documentation, as required 

under § 80.1451(b)(6), associated with 

feedstock purchases and transfers for a 

representative sample, selected in 

accordance with the guidelines in 

§ 80.127, of renewable fuel batches 

produced or imported during the year 

being reviewed. 

(A) If RINs were generated for a given 

batch of renewable fuel, verify that 

feedstocks used meet the definition of 

renewable biomass in § 80.1401. 

(B) If no RINs were generated for a 

given batch of renewable fuel, verify 

that feedstocks used do not meet the 

definition of renewable biomass in 

§ 80.1401 or that there was another 

reason that the fuel produced without 

RINs was not renewable fuel. 

(2) RIN transaction reports. (i) Obtain 

and read copies of a representative 

sample, selected in accordance with the 

guidelines in § 80.127, of each 

transaction type (RINs purchased, RINs 

sold, RINs retired, RINs reinstated) 

included in the RIN transaction reports 

required under § 80.1452(b)(2) for the 

compliance year. 

(ii) Obtain contracts, invoices, or 

other documentation for the 

representative samples of RIN 

transactions; compute the transaction 

types, transaction dates, and the RINs 

traded; state whether this information 

agrees with the party’s reports to EPA 

and report as a finding any exceptions. 

(3) RIN activity reports. (i) Obtain and 

read copies of the quarterly RIN activity 

reports required under § 80.1452(b)(3) 

for the compliance year. 

(ii) Obtain the database, spreadsheet, 

or other documentation used to generate 

the information in the RIN activity 

reports; compare the RIN transaction 

samples reviewed under paragraph 

(b)(2) of this section with the 

corresponding entries in the database or 

spreadsheet and report as a finding any 

discrepancies; compute the total 

number of current-year and prior-year 

RINs owned at the start and end of the 

quarter, purchased, sold, retired, and 

reinstated, and for parties that reported 

RIN activity for RINs assigned to a 

volume of renewable fuel, the volume of 

renewable fuel owned at the end of the 

quarter, as represented in these 

documents; and state whether this 

information agrees with the party’s 

reports to EPA. 

(4) Independent Third Party 

Engineering Review. (i) Obtain 

documentation of independent third 

party engineering review required under 

§ 80.1450(b)(2). 

(ii) Review and verify the written 

verification and records generated as 

part of the independent third party 

engineering review. 

(c) Other parties owning RINs. The 

following attest procedures shall be 

completed for any party other than an 

obligated party or renewable fuel 

producer or importer that owns any 

RINs during a calendar year: 

(1) RIN transaction reports. (i) Obtain 

and read copies of a representative 

sample, selected in accordance with the 

guidelines in § 80.127, of each RIN 

transaction type (RINs purchased, RINs 

sold, RINs retired, RINs reinstated) 

included in the RIN transaction reports 

required under § 80.1452(c)(1) for the 

compliance year. 

(ii) Obtain contracts, invoices, or 

other documentation for the 

representative samples of RIN 

transactions; compute the transaction 

types, transaction dates, and the RINs 

traded; state whether this information 

agrees with the party’s reports to EPA 

and report as a finding any exceptions. 

(2) RIN activity reports. (i) Obtain and 

read copies of the quarterly RIN activity 

reports required under § 80.1452(c)(2) 

for the compliance year. 

(ii) Obtain the database, spreadsheet, 

or other documentation used to generate 

the information in the RIN activity 

reports; compare the RIN transaction 

samples reviewed under paragraph 

(c)(1) of this section with the 

corresponding entries in the database or 

spreadsheet and report as a finding any 

discrepancies; compute the total 

number of current-year and prior-year 

RINs owned at the start and end of the 

quarter, purchased, sold, retired, and 

reinstated, and for parties that reported 

RIN activity for RINs assigned to a 

volume of renewable fuel, the volume of 

renewable fuel owned at the end of the 

quarter, as represented in these 

documents; and state whether this 

information agrees with the party’s 

reports to EPA. 

(d) The following submission dates 

apply to the attest engagements required 

under this section: 

(1) For each compliance year, each 

party subject to the attest engagement 

requirements under this section shall 

cause the reports required under this 

section to be submitted to EPA by May 

31 of the year following the compliance 

year. 

(2) [Reserved] 

(e) The party conducting the 

procedures under this section shall 

obtain a written representation from a 

company representative that the copies 

of the reports required under this 

section are complete and accurate 

copies of the reports filed with EPA. 

(f) The party conducting the 

procedures under this section shall 

identify and report as a finding the 

commercial computer program used by 

the party to track the data required by 

the regulations in this subpart, if any. 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25135 

§ 80.1465 What are the additional 

requirements under this subpart for foreign 

small refiners, foreign small refineries, and 

importers of RFS–FRFUEL? 

(a) Definitions. The following 

additional definitions apply for this 

subpart: 

(1) Foreign refinery is a refinery that 

is located outside the United States, the 

Commonwealth of Puerto Rico, the U.S. 

Virgin Islands, Guam, American Samoa, 

and the Commonwealth of the Northern 

Mariana Islands (collectively referred to 

in this section as ‘‘the United States’’). 

(2) Foreign refiner is a party that 

meets the definition of refiner under 

§ 80.2(i) for a foreign refinery. 

(3) Foreign small refiner is a foreign 

refiner that has received a small refinery 

exemption under § 80.1441 for one or 

more of its refineries or a foreign refiner 

that has received a small refiner 

exemption under § 80.1442. 

(4) RFS–FRFUEL is transportation fuel 

produced at a foreign refinery that has 

received a small refinery exemption 

under § 80.1441 or by a foreign refiner 

with a small refiner exemption under 

§ 80.1442. 

(5) Non-RFS–FRFUEL is one of the 

following: 

(i) Transportation fuel produced at a 

foreign refinery that has received a 

small refinery exemption under 

§ 80.1441 or by a foreign refiner with a 

small refiner exemption under 

§ 80.1442. 

(ii) Transportation fuel produced at a 

foreign refinery that has not received a 

small refinery exemption under 

§ 80.1441 or by a foreign refiner that has 

not received a small refiner exemption 

under § 80.1442. 

(b) General requirements for RFS– 

FRFUEL for foreign small refineries and 

small refiners. A foreign refiner must do 

all the following: 

(1) Designate, at the time of 

production, each batch of transportation 

fuel produced at the foreign refinery 

that is exported for use in the United 

States as RFS–FRFUEL. 

(2) Meet all requirements that apply to 

refiners who have received a small 

refinery or small refiner exemption 

under this subpart. 

(c) Designation, foreign small refiner 

certification, and product transfer 

documents. 

(1) Any foreign small refiner must 

designate each batch of RFS–FRFUEL as 

such at the time the transportation fuel 

is produced. 

(2) On each occasion when RFS– 

FRFUEL is loaded onto a vessel or other 

transportation mode for transport to the 

United States, the foreign small refiner 

shall prepare a certification for each 

batch of RFS–FRFUEL that meets all the 

following requirements: 

(i) The certification shall include the 

report of the independent third party 

under paragraph (d) of this section, and 

all the following additional information: 

(A) The name and EPA registration 

number of the refinery that produced 

the RFS–FRFUEL. 

(B) [Reserved] 

(ii) The identification of the 

transportation fuel as RFS–FRFUEL. 

(iii) The volume of RFS–FRFUEL 

being transported, in gallons. 

(3) On each occasion when any party 

transfers custody or title to any RFS– 

FRFUEL prior to its being imported into 

the United States, it must include all the 

following information as part of the 

product transfer document information: 

(i) Designation of the transportation 

fuel as RFS–FRFUEL. 

(ii) The certification required under 

paragraph (c)(2) of this section. 

(d) Load port independent testing and 

refinery identification. (1) On each 

occasion that RFS–FRFUEL is loaded 

onto a vessel for transport to the United 

States the foreign small refiner shall 

have an independent third party do all 

the following: 

(i) Inspect the vessel prior to loading 

and determine the volume of any tank 

bottoms. 

(ii) Determine the volume of RFS– 

FRFUEL loaded onto the vessel 

(exclusive of any tank bottoms before 

loading). 

(iii) Obtain the EPA-assigned 

registration number of the foreign 

refinery. 

(iv) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRFUEL to the 

United States. 

(v) Determine the date and time the 

vessel departs the port serving the 

foreign refinery. 

(vi) Review original documents that 

reflect movement and storage of the 

RFS–FRFUEL from the foreign refinery 

to the load port, and from this review 

determine: 

(A) The refinery at which the RFS– 

FRFUEL was produced; and 

(B) That the RFS–FRFUEL remained 

segregated from Non-RFS–FRFUEL and 

other RFS–FRFUEL produced at a 

different refinery. 

(2) The independent third party shall 

submit a report to all the following: 

(i) The foreign small refiner, 

containing the information required 

under paragraph (d)(1) of this section, to 

accompany the product transfer 

documents for the vessel. 

(ii) The Administrator, containing the 

information required under paragraph 

(d)(1) of this section, within thirty days 

following the date of the independent 

third party’s inspection. This report 

shall include a description of the 

method used to determine the identity 

of the refinery at which the 

transportation fuel was produced, 

assurance that the transportation fuel 

remained segregated as specified in 

paragraph (j)(1) of this section, and a 

description of the transportation fuel’s 

movement and storage between 

production at the source refinery and 

vessel loading. 

(3) The independent third party must 

do all the following: 

(i) Be approved in advance by EPA, 

based on a demonstration of ability to 

perform the procedures required in this 

paragraph (d). 

(ii) Be independent under the criteria 

specified in § 80.65(f)(2)(iii). 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities, 

facilities, and documents relevant to 

compliance with the requirements of 

this paragraph (d). 

(e) Comparison of load port and port 

of entry testing. (1)(i) Any foreign small 

refiner or foreign small refinery and any 

United States importer of RFS–FRFUEL 

shall compare the results from the load 

port testing under paragraph (d) of this 

section, with the port of entry testing as 

reported under paragraph (k) of this 

section, for the volume of transportation 

fuel, except as specified in paragraph 

(e)(1)(ii) of this section. 

(ii) Where a vessel transporting RFS– 

FRFUEL off loads this transportation 

fuel at more than one United States port 

of entry, the requirements of paragraph 

(e)(1)(i) of this section do not apply at 

subsequent ports of entry if the United 

States importer obtains a certification 

from the vessel owner that the 

requirements of paragraph (e)(1)(i) of 

this section were met and that the vessel 

has not loaded any transportation fuel 

or blendstock between the first United 

States port of entry and the subsequent 

port of entry. 

(2) If the temperature-corrected 

volumes determined at the port of entry 

and at the load port differ by more than 

one percent, the United States importer 

and the foreign small refiner or foreign 

small refinery shall not treat the 

transportation fuel as RFS–FRFUEL and 

the importer shall include the volume of 

transportation fuel in the importer’s RFS 

compliance calculations. 

(f) Foreign refiner commitments. Any 

small foreign refiner shall commit to 

and comply with the provisions 

contained in this paragraph (f) as a 

condition to being approved for a small 

refinery or small refiner exemption 

under this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

25136 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

must be given full, complete, and 

immediate access to conduct 

inspections and audits of the foreign 

refinery. 

(i) Inspections and audits may be 

either announced in advance by EPA, or 

unannounced. 

(ii) Access will be provided to any 

location where: 

(A) Transportation fuel is produced; 

(B) Documents related to refinery 

operations are kept; and 

(C) RFS–FRFUEL is stored or 

transported between the foreign refinery 

and the United States, including storage 

tanks, vessels and pipelines. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to all the following: 

(A) The volume of RFS–FRFUEL. 

(B) The proper classification of 

transportation fuel as being RFS– 

FRFUEL or as not being RFS–FRFUEL. 

(C) Transfers of title or custody to 

RFS–FRFUEL. 

(D) Testing of RFS–FRFUEL. 

(E) Work performed and reports 

prepared by independent third parties 

and by independent auditors under the 

requirements of this section, including 

work papers. 

(vi) Inspections and audits by EPA 

may include interviewing employees. 

(vii) Any employee of the foreign 

refiner must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 

(2) An agent for service of process 

located in the District of Columbia shall 

be named, and service on this agent 

constitutes service on the foreign refiner 

or any employee of the foreign refiner 

for any action by EPA or otherwise by 

the United States related to the 

requirements of this subpart. 

(3) The forum for any civil or criminal 

enforcement action related to the 

provisions of this section for violations 

of the Clean Air Act or regulations 

promulgated thereunder shall be 

governed by the Clean Air Act, 

including the EPA administrative forum 

where allowed under the Clean Air Act. 

(4) United States substantive and 

procedural laws shall apply to any civil 

or criminal enforcement action against 

the foreign refiner or any employee of 

the foreign refiner related to the 

provisions of this section. 

(5) Submitting an application for a 

small refinery or small refiner 

exemption, or producing and exporting 

transportation fuel under such 

exemption, and all other actions to 

comply with the requirements of this 

subpart relating to such exemption 

constitute actions or activities covered 

by and within the meaning of the 

provisions of 28 U.S.C. 1605(a)(2), but 

solely with respect to actions instituted 

against the foreign refiner, its agents and 

employees in any court or other tribunal 

in the United States for conduct that 

violates the requirements applicable to 

the foreign refiner under this subpart, 

including conduct that violates the 

False Statements Accountability Act of 

1996 (18 U.S.C. 1001) and section 

113(c)(2) of the Clean Air Act (42 U.S.C. 

7413). 

(6) The foreign refiner, or its agents or 

employees, will not seek to detain or to 

impose civil or criminal remedies 

against EPA inspectors or auditors, 

whether EPA employees or EPA 

contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (f) shall be signed by the 

owner or president of the foreign refiner 

business. 

(8) In any case where RFS–FRFUEL 

produced at a foreign refinery is stored 

or transported by another company 

between the refinery and the vessel that 

transports the RFS–FRFUEL to the 

United States, the foreign refiner shall 

obtain from each such other company a 

commitment that meets the 

requirements specified in paragraphs 

(f)(1) through (f)(7) of this section, and 

these commitments shall be included in 

the foreign refiner’s application for a 

small refinery or small refiner 

exemption under this subpart. 

(g) Sovereign immunity. By 

submitting an application for a small 

refinery or small refiner exemption 

under this subpart, or by producing and 

exporting transportation fuel to the 

United States under such exemption, 

the foreign refiner, and its agents and 

employees, without exception, become 

subject to the full operation of the 

administrative and judicial enforcement 

powers and provisions of the United 

States without limitation based on 

sovereign immunity, with respect to 

actions instituted against the foreign 

refiner, its agents and employees in any 

court or other tribunal in the United 

States for conduct that violates the 

requirements applicable to the foreign 

refiner under this subpart, including 

conduct that violates the False 

Statements Accountability Act of 1996 

(18 U.S.C. 1001) and section 113(c)(2) of 

the Clean Air Act (42 U.S.C. 7413). 

(h) Bond posting. Any foreign refiner 

shall meet the requirements of this 

paragraph (h) as a condition to approval 

of a small foreign refinery or small 

foreign refiner exemption under this 

subpart. 

(1) The foreign refiner shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $ 0.01 

Where: 

Bond = amount of the bond in United States 

dollars. 

G = the largest volume of transportation fuel 

produced at the foreign refinery and 

exported to the United States, in gallons, 

during a single calendar year among the 

most recent of the following calendar 

years, up to a maximum of five calendar 

years: the calendar year immediately 

preceding the date the refinery’s or 

refiner’s application is submitted, the 

calendar year the application is 

submitted, and each succeeding calendar 

year. 

(2) Bonds shall be posted by: 

(i) Paying the amount of the bond to 

the Treasurer of the United States; 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign refiner, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement; or 

(iii) An alternative commitment that 

results in assets of an appropriate 

liquidity and value being readily 

available to the United States, provided 

EPA agrees in advance as to the 

alternative commitment. 

(3) Bonds posted under this paragraph 

(h) shall: 

(i) Be used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart, including where such conduct 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413); 

(ii) Be provided by a corporate surety 

that is listed in the United States 

Department of Treasury Circular 570 

‘‘Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds’’; and 

(iii) Include a commitment that the 

bond will remain in effect for at least 

five years following the end of latest 

annual reporting period that the foreign 

refiner produces transportation fuel 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25137 

pursuant to the requirements of this 

subpart. 

(4) On any occasion a foreign refiner 

bond is used to satisfy any judgment, 

the foreign refiner shall increase the 

bond to cover the amount used within 

90 days of the date the bond is used. 

(5) If the bond amount for a foreign 

refiner increases, the foreign refiner 

shall increase the bond to cover the 

shortfall within 90 days of the date the 

bond amount changes. If the bond 

amount decreases, the foreign refiner 

may reduce the amount of the bond 

beginning 90 days after the date the 

bond amount changes. 

(i) English language reports. Any 

document submitted to EPA by a foreign 

refiner shall be in English, or shall 

include an English language translation. 

(j) Prohibitions. (1) No party may 

combine RFS–FRFUEL with any NonRFS–FRFUEL, and no party may 

combine RFS–FRFUEL with any RFS– 

FRFUEL produced at a different 

refinery, until the importer has met all 

the requirements of paragraph (k) of this 

section. 

(2) No foreign refiner or other party 

may cause another party to commit an 

action prohibited in paragraph (j)(1) of 

this section, or that otherwise violates 

the requirements of this section. 

(k) United States importer 

requirements. Any United States 

importer of RFS–FRFUEL shall meet the 

following requirements: 

(1) Each batch of imported RFS– 

FRFUEL shall be classified by the 

importer as being RFS–FRFUEL. 

(2) Transportation fuel shall be 

classified as RFS–FRFUEL according to 

the designation by the foreign refiner if 

this designation is supported by product 

transfer documents prepared by the 

foreign refiner as required in paragraph 

(c) of this section. Additionally, the 

importer shall comply with all 

requirements of this subpart applicable 

to importers. 

(3) For each transportation fuel batch 

classified as RFS–FRFUEL, any United 

States importer shall have an 

independent third party do all the 

following: 

(i) Determine the volume of 

transportation fuel in the vessel. 

(ii) Use the foreign refiner’s RFS– 

FRFUEL certification to determine the 

name and EPA-assigned registration 

number of the foreign refinery that 

produced the RFS–FRFUEL. 

(iii) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRFUEL to the 

United States. 

(iv) Determine the date and time the 

vessel arrives at the United States port 

of entry. 

(4) Any importer shall submit reports 

within 30 days following the date any 

vessel transporting RFS–FRFUEL arrives 

at the United States port of entry to: 

(i) The Administrator, containing the 

information determined under 

paragraph (k)(3) of this section; and 

(ii) The foreign refiner, containing the 

information determined under 

paragraph (k)(3)(i) of this section, and 

including identification of the port at 

which the product was off loaded. 

(5) Any United States importer shall 

meet all other requirements of this 

subpart for any imported transportation 

fuel that is not classified as RFS– 

FRFUEL under paragraph (k)(2) of this 

section. 

(l) Truck imports of RFS–FRFUEL 

produced at a foreign refinery. (1) Any 

refiner whose RFS–FRFUEL is 

transported into the United States by 

truck may petition EPA to use 

alternative procedures to meet all the 

following requirements: 

(i) Certification under paragraph (c)(2) 

of this section. 

(ii) Load port and port of entry testing 

requirements under paragraphs (d) and 

(e) of this section. 

(iii) Importer testing requirements 

under paragraph (k)(3) of this section. 

(2) These alternative procedures must 

ensure RFS–FRFUEL remains segregated 

from Non-RFS–FRFUEL until it is 

imported into the United States. The 

petition will be evaluated based on 

whether it adequately addresses all the 

following: 

(i) Provisions for monitoring pipeline 

shipments, if applicable, from the 

refinery, that ensure segregation of RFS– 

FRFUEL from that refinery from all 

other transportation fuel. 

(ii) Contracts with any terminals and/ 

or pipelines that receive and/or 

transport RFS–FRFUEL that prohibit the 

commingling of RFS–FRFUEL with 

Non-RFS–FRFUEL or RFS–FRFUEL 

from other foreign refineries. 

(iii) Attest procedures to be conducted 

annually by an independent third party 

that review loading records and import 

documents based on volume 

reconciliation, or other criteria, to 

confirm that all RFS–FRFUEL remains 

segregated throughout the distribution 

system. 

(3) The petition described in this 

section must be submitted to EPA along 

with the application for a small refinery 

or small refiner exemption under this 

subpart. 

(m) Additional attest requirements for 

importers of RFS–FRFUEL. The 

following additional procedures shall be 

carried out by any importer of RFS– 

FRFUEL as part of the attest engagement 

required for importers under this 

subpart M. 

(1) Obtain listings of all tenders of 

RFS–FRFUEL. Agree the total volume of 

tenders from the listings to the 

transportation fuel inventory 

reconciliation analysis required in 

§ 80.133(b), and to the volumes 

determined by the third party under 

paragraph (d) of this section. 

(2) For each tender under paragraph 

(m)(1) of this section, where the 

transportation fuel is loaded onto a 

marine vessel, report as a finding the 

name and country of registration of each 

vessel, and the volumes of RFS– 

FRFUEL loaded onto each vessel. 

(3) Select a sample from the list of 

vessels identified per paragraph (m)(2) 

of this section used to transport RFS– 

FRFUEL, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform all the 

following: 

(i) Obtain the report of the 

independent third party, under 

paragraph (d) of this section. 

(A) Agree the information in these 

reports with regard to vessel 

identification and transportation fuel 

volume. 

(B) Identify, and report as a finding, 

each occasion the load port and port of 

entry volume results differ by more than 

the amount allowed in paragraph (e)(2) 

of this section, and determine whether 

all of the requirements of paragraph 

(e)(2) of this section have been met. 

(ii) Obtain the documents used by the 

independent third party to determine 

transportation and storage of the RFS– 

FRFUEL from the refinery to the load 

port, under paragraph (d) of this section. 

Obtain tank activity records for any 

storage tank where the RFS–FRFUEL is 

stored, and pipeline activity records for 

any pipeline used to transport the RFS– 

FRFUEL prior to being loaded onto the 

vessel. Use these records to determine 

whether the RFS–FRFUEL was 

produced at the refinery that is the 

subject of the attest engagement, and 

whether the RFS–FRFUEL was mixed 

with any Non-RFS–FRFUEL or any 

RFS–FRFUEL produced at a different 

refinery. 

(4) Select a sample from the list of 

vessels identified per paragraph (m)(2) 

of this section used to transport RFS– 

FRFUEL, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform all the 

following: 

(i) Obtain a commercial document of 

general circulation that lists vessel 

arrivals and departures, and that 

includes the port and date of departure 

of the vessel, and the port of entry and 

date of arrival of the vessel. 

25138 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(ii) Agree the vessel’s departure and 

arrival locations and dates from the 

independent third party and United 

States importer reports to the 

information contained in the 

commercial document. 

(5) Obtain separate listings of all 

tenders of RFS–FRFUEL, and perform 

all the following: 

(i) Agree the volume of tenders from 

the listings to the transportation fuel 

inventory reconciliation analysis in 

§ 80.133(b). 

(ii) Obtain a separate listing of the 

tenders under this paragraph (m)(5) 

where the transportation fuel is loaded 

onto a marine vessel. Select a sample 

from this listing in accordance with the 

guidelines in § 80.127, and obtain a 

commercial document of general 

circulation that lists vessel arrivals and 

departures, and that includes the port 

and date of departure and the ports and 

dates where the transportation fuel was 

off loaded for the selected vessels. 

Determine and report as a finding the 

country where the transportation fuel 

was off loaded for each vessel selected. 

(6) In order to complete the 

requirements of this paragraph (m), an 

auditor shall do all the following: 

(i) Be independent of the foreign 

refiner or importer. 

(ii) Be licensed as a Certified Public 

Accountant in the United States and a 

citizen of the United States, or be 

approved in advance by EPA based on 

a demonstration of ability to perform the 

procedures required in §§ 80.125 

through 80.127, 80.130, 80.1464, and 

this paragraph (m). 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities 

and documents relevant to compliance 

with the requirements of §§ 80.125 

through 80.127, 80.130, 80.1464, and 

this paragraph (m). 

(n) Withdrawal or suspension of 

foreign small refiner or foreign small 

refinery status. EPA may withdraw or 

suspend a foreign refiner’s small 

refinery or small refiner exemption 

where: 

(1) A foreign refiner fails to meet any 

requirement of this section; 

(2) A foreign government fails to 

allow EPA inspections as provided in 

paragraph (f)(1) of this section; 

(3) A foreign refiner asserts a claim of, 

or a right to claim, sovereign immunity 

in an action to enforce the requirements 

in this subpart; or 

(4) A foreign refiner fails to pay a civil 

or criminal penalty that is not satisfied 

using the foreign refiner bond specified 

in paragraph (h) of this section. 

(o) Additional requirements for 

applications, reports and certificates. 

Any application for a small refinery or 

small refiner exemption, alternative 

procedures under paragraph (l) of this 

section, any report, certification, or 

other submission required under this 

section shall be: 

(1) Submitted in accordance with 

procedures specified by the 

Administrator, including use of any 

forms that may be specified by the 

Administrator. 

(2) Signed by the president or owner 

of the foreign refiner company, or by 

that party’s immediate designee, and 

shall contain the following declaration: 

‘‘I hereby certify: (1) That I have 

actual authority to sign on behalf of and 

to bind [insert name of foreign refiner] 

with regard to all statements contained 

herein; (2) that I am aware that the 

information contained herein is being 

Certified, or submitted to the United 

States Environmental Protection 

Agency, under the requirements of 40 

CFR part 80, subpart M, and that the 

information is material for determining 

compliance under these regulations; and 

(3) that I have read and understand the 

information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to 

verify the accuracy thereof. I affirm that 

I have read and understand the 

provisions of 40 CFR part 80, subpart M, 

including 40 CFR 80.1465 apply to 

[INSERT NAME OF FOREIGN 

REFINER]. Pursuant to Clean Air Act 

section 113(c) and 18 U.S.C. 1001, the 

penalty for furnishing false, incomplete 

or misleading information in this 

certification or submission is a fine of 

up to $10,000 U.S., and/or 

imprisonment for up to five years.’’. 

§ 80.1466 What are the additional 

requirements under this subpart for foreign 

producers and importers of renewable 

fuels? 

(a) Foreign producer of renewable 

fuel. For purposes of this subpart, a 

foreign producer of renewable fuel is a 

party located outside the United States, 

the Commonwealth of Puerto Rico, the 

Virgin Islands, Guam, American Samoa, 

and the Commonwealth of the Northern 

Mariana Islands (collectively referred to 

in this section as ‘‘the United States’’) 

that has been approved by EPA to assign 

RINs to renewable fuel that the foreign 

producer produces and exports to the 

United States, hereinafter referred to as 

a ‘‘foreign producer’’ under this section. 

(b) General requirements. An 

approved foreign producer under this 

section must meet all requirements that 

apply to renewable fuel producers 

under this subpart. 

(c) Designation, foreign producer 

certification, and product transfer 

documents. (1) Any approved foreign 

producer under this section must 

designate each batch of renewable fuel 

as ‘‘RFS–FRRF’’ at the time the 

renewable fuel is produced. 

(2) On each occasion when RFS–FRRF 

is loaded onto a vessel or other 

transportation mode for transport to the 

United States, the foreign producer shall 

prepare a certification for each batch of 

RFS–FRRF; the certification shall 

include the report of the independent 

third party under paragraph (d) of this 

section, and all the following additional 

information: 

(i) The name and EPA registration 

number of the company that produced 

the RFS–FRRF. 

(ii) The identification of the 

renewable fuel as RFS–FRRF. 

(iii) The volume of RFS–FRRF being 

transported, in gallons. 

(3) On each occasion when any party 

transfers custody or title to any RFS– 

FRRF prior to its being imported into 

the United States, it must include all the 

following information as part of the 

product transfer document information: 

(i) Designation of the renewable fuel 

as RFS–FRRF. 

(ii) The certification required under 

paragraph (c)(2) of this section. 

(d) Load port independent testing and 

refinery identification. (1) On each 

occasion that RFS–FRRF is loaded onto 

a vessel for transport to the United 

States the foreign producer shall have 

an independent third party do all the 

following: 

(i) Inspect the vessel prior to loading 

and determine the volume of any tank 

bottoms. 

(ii) Determine the volume of RFS– 

FRRF loaded onto the vessel (exclusive 

of any tank bottoms before loading). 

(iii) Obtain the EPA-assigned 

registration number of the foreign 

producer. 

(iv) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRRF to the United 

States. 

(v) Determine the date and time the 

vessel departs the port serving the 

foreign producer. 

(vi) Review original documents that 

reflect movement and storage of the 

RFS–FRRF from the foreign producer to 

the load port, and from this review 

determine all the following: 

(A) The facility at which the RFS– 

FRRF was produced. 

(B) That the RFS–FRRF remained 

segregated from Non-RFS–FRRF and 

other RFS–FRRF produced by a 

different foreign producer. 

(2) The independent third party shall 

submit a report to the following: 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25139 

(i) The foreign producer, containing 

the information required under 

paragraph (d)(1) of this section, to 

accompany the product transfer 

documents for the vessel. 

(ii) The Administrator, containing the 

information required under paragraph 

(d)(1) of this section, within thirty days 

following the date of the independent 

third party’s inspection. This report 

shall include a description of the 

method used to determine the identity 

of the foreign producer facility at which 

the renewable fuel was produced, 

assurance that the renewable fuel 

remained segregated as specified in 

paragraph (j)(1) of this section, and a 

description of the renewable fuel’s 

movement and storage between 

production at the source facility and 

vessel loading. 

(3) The independent third party must: 

(i) Be approved in advance by EPA, 

based on a demonstration of ability to 

perform the procedures required in this 

paragraph (d); 

(ii) Be independent under the criteria 

specified in § 80.65(e)(2)(iii); and 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities, 

facilities and documents relevant to 

compliance with the requirements of 

this paragraph (d). 

(e) Comparison of load port and port 

of entry testing. (1)(i) Any foreign 

producer and any United States 

importer of RFS–FRRF shall compare 

the results from the load port testing 

under paragraph (d) of this section, with 

the port of entry testing as reported 

under paragraph (k) of this section, for 

the volume of renewable fuel, except as 

specified in paragraph (e)(1)(ii) of this 

section. 

(ii) Where a vessel transporting RFS– 

FRRF off loads the renewable fuel at 

more than one United States port of 

entry, the requirements of paragraph 

(e)(1)(i) of this section do not apply at 

subsequent ports of entry if the United 

States importer obtains a certification 

from the vessel owner that the 

requirements of paragraph (e)(1)(i) of 

this section were met and that the vessel 

has not loaded any renewable fuel 

between the first United States port of 

entry and the subsequent port of entry. 

(2)(i) If the temperature-corrected 

volumes determined at the port of entry 

and at the load port differ by more than 

one percent, the number of RINs 

associated with the renewable fuel shall 

be calculated based on the lesser of the 

two volumes in paragraph (e)(1)(i) of 

this section. 

(ii) Where the port of entry volume is 

the lesser of the two volumes in 

paragraph (e)(1)(i) of this section, the 

importer shall calculate the difference 

between the number of RINs originally 

assigned by the foreign producer and 

the number of RINs calculated under 

§ 80.1426 for the volume of renewable 

fuel as measured at the port of entry, 

and retire that amount of RINs in 

accordance with paragraph (k)(4) of this 

section. 

(f) Foreign producer commitments. 

Any foreign producer shall commit to 

and comply with the provisions 

contained in this paragraph (f) as a 

condition to being approved as a foreign 

producer under this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

must be given full, complete, and 

immediate access to conduct 

inspections and audits of the foreign 

producer facility. 

(i) Inspections and audits may be 

either announced in advance by EPA, or 

unannounced. 

(ii) Access will be provided to any 

location where: 

(A) Renewable fuel is produced; 

(B) Documents related to renewable 

fuel producer operations are kept; and 

(C) RFS–FRRF is stored or transported 

between the foreign producer and the 

United States, including storage tanks, 

vessels and pipelines. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to the following: 

(A) The volume of RFS–FRRF. 

(B) The proper classification of 

gasoline as being RFS–FRRF. 

(C) Transfers of title or custody to 

RFS–FRRF. 

(D) Work performed and reports 

prepared by independent third parties 

and by independent auditors under the 

requirements of this section, including 

work papers. 

(vi) Inspections and audits by EPA 

may include interviewing employees. 

(vii) Any employee of the foreign 

producer must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 

(2) An agent for service of process 

located in the District of Columbia shall 

be named, and service on this agent 

constitutes service on the foreign 

producer or any employee of the foreign 

producer for any action by EPA or 

otherwise by the United States related to 

the requirements of this subpart. 

(3) The forum for any civil or criminal 

enforcement action related to the 

provisions of this section for violations 

of the Clean Air Act or regulations 

promulgated thereunder shall be 

governed by the Clean Air Act, 

including the EPA administrative forum 

where allowed under the Clean Air Act. 

(4) United States substantive and 

procedural laws shall apply to any civil 

or criminal enforcement action against 

the foreign producer or any employee of 

the foreign producer related to the 

provisions of this section. 

(5) Applying to be an approved 

foreign producer under this section, or 

producing or exporting renewable fuel 

under such approval, and all other 

actions to comply with the requirements 

of this subpart relating to such approval 

constitute actions or activities covered 

by and within the meaning of the 

provisions of 28 U.S.C. 1605(a)(2), but 

solely with respect to actions instituted 

against the foreign producer, its agents 

and employees in any court or other 

tribunal in the United States for conduct 

that violates the requirements 

applicable to the foreign producer under 

this subpart, including conduct that 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413). 

(6) The foreign producer, or its agents 

or employees, will not seek to detain or 

to impose civil or criminal remedies 

against EPA inspectors or auditors, 

whether EPA employees or EPA 

contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (f) shall be signed by the 

owner or president of the foreign 

producer company. 

(8) In any case where RFS–FRRF 

produced at a foreign producer facility 

is stored or transported by another 

company between the refinery and the 

vessel that transports the RFS–FRRF to 

the United States, the foreign producer 

shall obtain from each such other 

company a commitment that meets the 

requirements specified in paragraphs 

(f)(1) through (7) of this section, and 

these commitments shall be included in 

the foreign producer’s application to be 

an approved foreign producer under this 

subpart. 

(g) Sovereign immunity. By 

submitting an application to be an 

approved foreign producer under this 

25140 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

subpart, or by producing and exporting 

renewable fuel to the United States 

under such approval, the foreign 

producer, and its agents and employees, 

without exception, become subject to 

the full operation of the administrative 

and judicial enforcement powers and 

provisions of the United States without 

limitation based on sovereign immunity, 

with respect to actions instituted against 

the foreign producer, its agents and 

employees in any court or other tribunal 

in the United States for conduct that 

violates the requirements applicable to 

the foreign producer under this subpart, 

including conduct that violates the 

False Statements Accountability Act of 

1996 (18 U.S.C. 1001) and section 

113(c)(2) of the Clean Air Act (42 U.S.C. 

7413). 

(h) Bond posting. Any foreign 

producer shall meet the requirements of 

this paragraph (h) as a condition to 

approval as a foreign producer under 

this subpart. 

(1) The foreign producer shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $ 0.01 

Where: 

Bond = amount of the bond in U.S. dollars. 

G = the largest volume of renewable fuel 

produced at the foreign producer’s 

facility and exported to the United 

States, in gallons, during a single 

calendar year among the most recent of 

the following calendar years, up to a 

maximum of five calendar years: the 

calendar year immediately preceding the 

date the refinery’s application is 

submitted, the calendar year the 

application is submitted, and each 

succeeding calendar year. 

(2) Bonds shall be posted by any of 

the following methods: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign producer, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 

(iii) An alternative commitment that 

results in assets of an appropriate 

liquidity and value being readily 

available to the United States provided 

EPA agrees in advance as to the 

alternative commitment. 

(3) Bonds posted under this paragraph 

(h) shall: 

(i) Be used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart, including where such conduct 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413); 

(ii) Be provided by a corporate surety 

that is listed in the United States 

Department of Treasury Circular 570 

‘‘Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds’’; and 

(iii) Include a commitment that the 

bond will remain in effect for at least 

five years following the end of latest 

annual reporting period that the foreign 

producer produces renewable fuel 

pursuant to the requirements of this 

subpart. 

(4) On any occasion a foreign 

producer bond is used to satisfy any 

judgment, the foreign producer shall 

increase the bond to cover the amount 

used within 90 days of the date the 

bond is used. 

(5) If the bond amount for a foreign 

producer increases, the foreign producer 

shall increase the bond to cover the 

shortfall within 90 days of the date the 

bond amount changes. If the bond 

amount decreases, the foreign refiner 

may reduce the amount of the bond 

beginning 90 days after the date the 

bond amount changes. 

(i) English language reports. Any 

document submitted to EPA by a foreign 

producer shall be in English, or shall 

include an English language translation. 

(j) Prohibitions. (1) No party may 

combine RFS–FRRF with any Non-RFS– 

FRRF, and no party may combine RFS– 

FRRF with any RFS–FRRF produced at 

a different refinery, until the importer 

has met all the requirements of 

paragraph (k) of this section. 

(2) No foreign producer or other party 

may cause another party to commit an 

action prohibited in paragraph (j)(1) of 

this section, or that otherwise violates 

the requirements of this section. 

(k) Requirements for United States 

importers of RFS–FRRF. Any United 

States importer shall meet all the 

following requirements: 

(1) Each batch of imported RFS–FRRF 

shall be classified by the importer as 

being RFS–FRRF. 

(2) Renewable fuel shall be classified 

as RFS–FRRF according to the 

designation by the foreign producer if 

this designation is supported by product 

transfer documents prepared by the 

foreign producer as required in 

paragraph (c) of this section. 

(3) For each renewable fuel batch 

classified as RFS–FRRF, any United 

States importer shall have an 

independent third party do all the 

following: 

(i) Determine the volume of gasoline 

in the vessel. 

(ii) Use the foreign producer’s RFS– 

FRRF certification to determine the 

name and EPA-assigned registration 

number of the foreign producer that 

produced the RFS–FRRF. 

(iii) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRRF to the United 

States. 

(iv) Determine the date and time the 

vessel arrives at the United States port 

of entry. 

(4) Where the importer is required to 

retire RINs under paragraph (e)(2) of this 

section, the importer must report the 

retired RINs in the applicable reports 

under § 80.1452. 

(5) Any importer shall submit reports 

within 30 days following the date any 

vessel transporting RFS–FRRF arrives at 

the United States port of entry to all the 

following: 

(i) The Administrator, containing the 

information determined under 

paragraph (k)(3) of this section. 

(ii) The foreign producer, containing 

the information determined under 

paragraph (k)(3)(i) of this section, and 

including identification of the port at 

which the product was off loaded, and 

any RINs retired under paragraph (e)(2) 

of this section. 

(6) Any United States importer shall 

meet all other requirements of this 

subpart for any imported ethanol or 

other renewable fuel that is not 

classified as RFS–FRRF under 

paragraph (k)(2) of this section. 

(l) Truck imports of RFS–FRRF 

produced by a foreign producer. (1) Any 

foreign producer whose RFS–FRRF is 

transported into the United States by 

truck may petition EPA to use 

alternative procedures to meet all the 

following requirements: 

(i) Certification under paragraph (c)(2) 

of this section. 

(ii) Load port and port of entry testing 

under paragraphs (d) and (e) of this 

section. 

(iii) Importer testing under paragraph 

(k)(3) of this section. 

(2) These alternative procedures must 

ensure RFS–FRRF remains segregated 

from Non-RFS–FRRF until it is 

imported into the United States. The 

petition will be evaluated based on 

whether it adequately addresses the 

following: 

(i) Contracts with any facilities that 

receive and/or transport RFS–FRRF that 

prohibit the commingling of RFS–FRRF 

with Non-RFS–FRRF or RFS–FRRF from 

other foreign producers. 

(ii) Attest procedures to be conducted 

annually by an independent third party 

that review loading records and import 

documents based on volume 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25141 

reconciliation to confirm that all RFS– 

FRRF remains segregated. 

(3) The petition described in this 

section must be submitted to EPA along 

with the application for approval as a 

foreign producer under this subpart. 

(m) Additional attest requirements for 

producers of RFS–FRRF. The following 

additional procedures shall be carried 

out by any producer of RFS–FRRF as 

part of the attest engagement required 

for renewable fuel producers under this 

subpart M. 

(1) Obtain listings of all tenders of 

RFS–FRRF. Agree the total volume of 

tenders from the listings to the volumes 

determined by the third party under 

paragraph (d) of this section. 

(2) For each tender under paragraph 

(m)(1) of this section, where the 

renewable fuel is loaded onto a marine 

vessel, report as a finding the name and 

country of registration of each vessel, 

and the volumes of RFS–FRRF loaded 

onto each vessel. 

(3) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS– 

FRRF, in accordance with the guidelines 

in § 80.127, and for each vessel selected 

perform all the following: 

(i) Obtain the report of the 

independent third party, under 

paragraph (d) of this section, and of the 

United States importer under paragraph 

(k) of this section. 

(A) Agree the information in these 

reports with regard to vessel 

identification and renewable fuel 

volume. 

(B) Identify, and report as a finding, 

each occasion the load port and port of 

entry volume results differ by more than 

the amount allowed in paragraph (e) of 

this section, and determine whether the 

importer retired the appropriate amount 

of RINs as required under paragraph 

(e)(2) of this section, and submitted the 

applicable reports under § 80.1452 in 

accordance with paragraph (k)(4) of this 

section. 

(ii) Obtain the documents used by the 

independent third party to determine 

transportation and storage of the RFS– 

FRRF from the foreign producer’s 

facility to the load port, under 

paragraph (d) of this section. Obtain 

tank activity records for any storage tank 

where the RFS–FRRF is stored, and 

activity records for any mode of 

transportation used to transport the 

RFS–FRFUEL prior to being loaded onto 

the vessel. Use these records to 

determine whether the RFS–FRRF was 

produced at the foreign producer’s 

facility that is the subject of the attest 

engagement, and whether the RFS– 

FRRF was mixed with any Non-RFS– 

FRRF or any RFS–FRRF produced at a 

different facility. 

(4) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS– 

FRRF, in accordance with the guidelines 

in § 80.127, and for each vessel selected 

perform the following: 

(i) Obtain a commercial document of 

general circulation that lists vessel 

arrivals and departures, and that 

includes the port and date of departure 

of the vessel, and the port of entry and 

date of arrival of the vessel. 

(ii) Agree the vessel’s departure and 

arrival locations and dates from the 

independent third party and United 

States importer reports to the 

information contained in the 

commercial document. 

(5) Obtain a separate listing of the 

tenders under this paragraph (m)(5) 

where the RFS–FRRF is loaded onto a 

marine vessel. Select a sample from this 

listing in accordance with the 

guidelines in § 80.127, and obtain a 

commercial document of general 

circulation that lists vessel arrivals and 

departures, and that includes the port 

and date of departure and the ports and 

dates where the renewable fuel was off 

loaded for the selected vessels. 

Determine and report as a finding the 

country where the renewable fuel was 

off loaded for each vessel selected. 

(6) In order to complete the 

requirements of this paragraph (m) an 

auditor shall: 

(i) Be independent of the foreign 

producer; 

(ii) Be licensed as a Certified Public 

Accountant in the United States and a 

citizen of the United States, or be 

approved in advance by EPA based on 

a demonstration of ability to perform the 

procedures required in §§ 80.125 

through 80.127, 80.130, 80.1464, and 

this paragraph (m); and 

(iii) Sign a commitment that contains 

the provisions specified in paragraph (f) 

of this section with regard to activities 

and documents relevant to compliance 

with the requirements of §§ 80.125 

through 80.127, 80.130, 80.1464, and 

this paragraph (m). 

(n) Withdrawal or suspension of 

foreign producer approval. EPA may 

withdraw or suspend a foreign 

producer’s approval where any of the 

following occur: 

(1) A foreign producer fails to meet 

any requirement of this section. 

(2) A foreign government fails to 

allow EPA inspections as provided in 

paragraph (f)(1) of this section. 

(3) A foreign producer asserts a claim 

of, or a right to claim, sovereign 

immunity in an action to enforce the 

requirements in this subpart. 

(4) A foreign producer fails to pay a 

civil or criminal penalty that is not 

satisfied using the foreign producer 

bond specified in paragraph (g) of this 

section. 

(o) Additional requirements for 

applications, reports and certificates. 

Any application for approval as a 

foreign producer, alternative procedures 

under paragraph (l) of this section, any 

report, certification, or other submission 

required under this section shall be: 

(1) Submitted in accordance with 

procedures specified by the 

Administrator, including use of any 

forms that may be specified by the 

Administrator. 

(2) Signed by the president or owner 

of the foreign producer company, or by 

that party’s immediate designee, and 

shall contain the following declaration: 

‘‘I hereby certify: 1) That I have actual 

authority to sign on behalf of and to 

bind [insert name of foreign producer] 

with regard to all statements contained 

herein; 2) that I am aware that the 

information contained herein is being 

Certified, or submitted to the United 

States Environmental Protection 

Agency, under the requirements of 40 

CFR part 80, subpart M, and that the 

information is material for determining 

compliance under these regulations; and 

3) that I have read and understand the 

information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to 

verify the accuracy thereof. I affirm that 

I have read and understand the 

provisions of 40 CFR part 80, subpart M, 

including 40 CFR 80.1465 apply to 

[insert name of foreign producer]. 

Pursuant to Clean Air Act section 113(c) 

and 18 U.S.C. 1001, the penalty for 

furnishing false, incomplete or 

misleading information in this 

certification or submission is a fine of 

up to $10,000 U.S., and/or 

imprisonment for up to five years.’’. 

§ 80.1467 What are the additional 

requirements under this subpart for a 

foreign RIN owner? 

(a) Foreign RIN owner. For purposes 

of this subpart, a foreign RIN owner is 

a party located outside the United 

States, the Commonwealth of Puerto 

Rico, the Virgin Islands, Guam, 

American Samoa, and the 

Commonwealth of the Northern Mariana 

Islands (collectively referred to in this 

section as ‘‘the United States’’) that has 

been approved by EPA to own RINs. 

(b) General requirement. An approved 

foreign RIN owner must meet all 

requirements that apply to parties who 

own RINs under this subpart. 

25142 Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 

(c) Foreign RIN owner commitments. 

Any party shall commit to and comply 

with the provisions contained in this 

paragraph (c) as a condition to being 

approved as a foreign RIN owner under 

this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

must be given full, complete, and 

immediate access to conduct 

inspections and audits of the foreign 

RIN owner’s place of business. 

(i) Inspections and audits may be 

either announced in advance by EPA, or 

unannounced. 

(ii) Access will be provided to any 

location where documents related to 

RINs the foreign RIN owner has 

obtained, sold, transferred or held are 

kept. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to the following: 

(A) Transfers of title to RINs. 

(B) Work performed and reports 

prepared by independent auditors under 

the requirements of this section, 

including work papers. 

(vi) Inspections and audits by EPA 

may include interviewing employees. 

(vii) Any employee of the foreign RIN 

owner must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 

(2) An agent for service of process 

located in the District of Columbia shall 

be named, and service on this agent 

constitutes service on the foreign RIN 

owner or any employee of the foreign 

RIN owner for any action by EPA or 

otherwise by the United States related to 

the requirements of this subpart. 

(3) The forum for any civil or criminal 

enforcement action related to the 

provisions of this section for violations 

of the Clean Air Act or regulations 

promulgated thereunder shall be 

governed by the Clean Air Act, 

including the EPA administrative forum 

where allowed under the Clean Air Act. 

(4) United States substantive and 

procedural laws shall apply to any civil 

or criminal enforcement action against 

the foreign RIN owner or any employee 

of the foreign RIN owner related to the 

provisions of this section. 

(5) Submitting an application to be a 

foreign RIN owner, and all other actions 

to comply with the requirements of this 

subpart constitute actions or activities 

covered by and within the meaning of 

the provisions of 28 U.S.C. 1605(a)(2), 

but solely with respect to actions 

instituted against the foreign RIN owner, 

its agents and employees in any court or 

other tribunal in the United States for 

conduct that violates the requirements 

applicable to the foreign RIN owner 

under this subpart, including conduct 

that violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413). 

(6) The foreign RIN owner, or its 

agents or employees, will not seek to 

detain or to impose civil or criminal 

remedies against EPA inspectors or 

auditors, whether EPA employees or 

EPA contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (c) shall be signed by the 

owner or president of the foreign RIN 

owner business. 

(d) Sovereign immunity. By 

submitting an application to be a foreign 

RIN owner under this subpart, the 

foreign entity, and its agents and 

employees, without exception, become 

subject to the full operation of the 

administrative and judicial enforcement 

powers and provisions of the United 

States without limitation based on 

sovereign immunity, with respect to 

actions instituted against the foreign 

RIN owner, its agents and employees in 

any court or other tribunal in the United 

States for conduct that violates the 

requirements applicable to the foreign 

RIN owner under this subpart, including 

conduct that violates the False 

Statements Accountability Act of 1996 

(18 U.S.C. 1001) and section 113(c)(2) of 

the Clean Air Act (42 U.S.C. 7413). 

(e) Bond posting. Any foreign entity 

shall meet the requirements of this 

paragraph (e) as a condition to approval 

as a foreign RIN owner under this 

subpart. 

(1) The foreign entity shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $ 0.01 

Where: 

Bond = amount of the bond in U.S. dollars. 

G = the total of the number of gallon-RINs the 

foreign entity expects to sell or transfer 

during the first calendar year that the 

foreign entity is a RIN owner, plus the 

number of gallon-RINs the foreign entity 

expects to sell or transfer during the next 

four calendar years. After the first 

calendar year, the bond amount shall be 

based on the actual number of gallonRINs sold or transferred during the 

current calendar year and the number 

held at the conclusion of the current 

averaging year, plus the number of 

gallon-RINs sold or transferred during 

the four most recent calendar years 

preceding the current calendar year. For 

any year for which there were fewer than 

four preceding years in which the foreign 

entity sold or transferred RINs, the bond 

shall be based on the total of the number 

of gallon-RINs sold or transferred during 

the current calendar year and the 

number held at the end of the current 

calendar year, plus the number of gallonRINs sold or transferred during any 

calendar year preceding the current 

calendar year, plus the number of gallonRINs expected to be sold or transferred 

during subsequent calendar years, the 

total number of years not to exceed four 

calendar years in addition to the current 

calendar year. 

(2) Bonds shall be posted by doing 

any of the following: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign RIN owner, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 

(iii) An alternative commitment that 

results in assets of an appropriate 

liquidity and value being readily 

available to the United States, provided 

EPA agrees in advance as to the 

alternative commitment. 

(3) All the following shall apply to 

bonds posted under this paragraph (e); 

bonds shall: 

(i) Be used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart, including where such conduct 

violates the False Statements 

Accountability Act of 1996 (18 U.S.C. 

1001) and section 113(c)(2) of the Clean 

Air Act (42 U.S.C. 7413). 

(ii) Be provided by a corporate surety 

that is listed in the United States 

Department of Treasury Circular 570 

‘‘Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds’’. 

(iii) Include a commitment that the 

bond will remain in effect for at least 

five years following the end of latest 

reporting period in which the foreign 

RIN owner obtains, sells, transfers, or 

holds RINs. 

(4) On any occasion a foreign RIN 

owner bond is used to satisfy any 

judgment, the foreign RIN owner shall 

increase the bond to cover the amount 

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed Rules 25143 

used within 90 days of the date the 

bond is used. 

(f) English language reports. Any 

document submitted to EPA by a foreign 

RIN owner shall be in English, or shall 

include an English language translation. 

(g) Prohibitions. (1) A foreign RIN 

owner is prohibited from obtaining, 

selling, transferring, or holding any RIN 

that is in excess of the number for 

which the bond requirements of this 

section have been satisfied. 

(2) Any RIN that is sold, transferred, 

or held that is in excess of the number 

for which the bond requirements of this 

section have been satisfied is an invalid 

RIN under § 80.1431. 

(3) Any RIN that is obtained from a 

party located outside the United States 

that is not an approved foreign RIN 

owner under this section is an invalid 

RIN under § 80.1431. 

(4) No foreign RIN owner or other 

party may cause another party to 

commit an action prohibited in this 

paragraph (g), or that otherwise violates 

the requirements of this section. 

(h) Additional attest requirements for 

foreign RIN owners. The following 

additional requirements apply to any 

foreign RIN owner as part of the attest 

engagement required for RIN owners 

under this subpart M. 

(i) The attest auditor must be 

independent of the foreign RIN owner. 

(ii) The attest auditor must be 

licensed as a Certified Public 

Accountant in the United States and a 

citizen of the United States, or be 

approved in advance by EPA based on 

a demonstration of ability to perform the 

procedures required in §§ 80.125 

through 80.127, 80.130, and 80.1464. 

(iii) The attest auditor must sign a 

commitment that contains the 

provisions specified in paragraph (c) of 

this section with regard to activities and 

documents relevant to compliance with 

the requirements of §§ 80.125 through 

80.127, 80.130, and 80.1464. 

(i) Withdrawal or suspension of 

foreign RIN owner status. EPA may 

withdraw or suspend its approval of a 

foreign RIN owner where any of the 

following occur: 

(1) A foreign RIN owner fails to meet 

any requirement of this section, 

including, but not limited to, the bond 

requirements. 

(2) A foreign government fails to 

allow EPA inspections as provided in 

paragraph (c)(1) of this section. 

(3) A foreign RIN owner asserts a 

claim of, or a right to claim, sovereign 

immunity in an action to enforce the 

requirements in this subpart. 

(4) A foreign RIN owner fails to pay 

a civil or criminal penalty that is not 

satisfied using the foreign RIN owner 

bond specified in paragraph (e) of this 

section. 

(j) Additional requirements for 

applications, reports and certificates. 

Any application for approval as a 

foreign RIN owner, any report, 

certification, or other submission 

required under this section shall be: 

(1) Submitted in accordance with 

procedures specified by the 

Administrator, including use of any 

forms that may be specified by the 

Administrator. 

(2) Signed by the president or owner 

of the foreign RIN owner company, or 

by that party’s immediate designee, and 

shall contain the following declaration: 

‘‘I hereby certify: 1) That I have actual 

authority to sign on behalf of and to 

bind [insert name of foreign RIN owner] 

with regard to all statements contained 

herein; 2) that I am aware that the 

information contained herein is being 

Certified, or submitted to the United 

States Environmental Protection 

Agency, under the requirements of 40 

CFR part 80, subpart M, and that the 

information is material for determining 

compliance under these regulations; and 

3) that I have read and understand the 

information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to 

verify the accuracy thereof. I affirm that 

I have read and understand the 

provisions of 40 CFR part 80, subpart M, 

including 40 CFR 80.1467 apply to 

[insert name of foreign RIN owner]. 

Pursuant to Clean Air Act section 113(c) 

and 18 U.S.C. 1001, the penalty for 

furnishing false, incomplete or 

misleading information in this 

certification or submission is a fine of 

up to $10,000 U.S., and/or 

imprisonment for up to five years.’’. 

§ 80.1468 [Reserved] 

§ 80.1469 What are the labeling 

requirements that apply to retailers and 

wholesale purchaser-consumers of ethanol 

fuel blends that contain greater than 10 

volume percent ethanol? 

(a) Any retailer or wholesale 

purchaser-consumer who sells, 

dispenses, or offers for sale or 

dispensing, ethanol fuel blends that 

contain greater than 10 volume percent 

ethanol must prominently and 

conspicuously display in the immediate 

area of each pump stand from which 

such fuel is offered for sale or 

dispensing, the following legible label 

in block letters of no less than 24-point 

bold type in a color contrasting with the 

background: 

CONTAINS MORE THAN 10 VOLUME 

PERCENT ETHANOL 

For use only in flexible-fuel gasoline 

vehicles. 

May damage non-flexible fuel 

vehicles. 

WARNING 

Federal law prohibits use in nonflexible fuel vehicles. 

(b) Alternative labels to those 

specified in paragraph (a) of this section 

may be used as approved by EPA. 

Requests for approval of alternative 

labels shall be sent to one of the 

following addresses: 

(1) For US mail: U.S. EPA, Attn: 

Alternative fuel dispenser label request, 

6406J, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: Alternative fuel 

dispenser label request, 6406J, 1310 L 

Street, NW., 6th floor, Washington, DC 

20005. (202) 343–9038. 

[FR Doc. E9–10978 Filed 5–22–09; 8:45 am] 

BILLING CODE 6560–50–P